Eversource 2004 Annual Report Download - page 29

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In January 2005, the New England transmission owners voted affirmatively
to approve activation of the RTO, which occurred on February 1, 2005.
As of February 1, 2005, transmission rates were adjusted to reflect
the ROEs proposed by the New England transmission owners in the
original RTO filing (12.8 percent plus the requested 0.5 percent),
subject to refund to reflect the ROE resulting from the ultimate
outcome of the hearings. Management cannot at this time predict
the ultimate ROE that will be determined following the hearings.
Utility Group Regulatory Issues and Rate Matters
Transmission: Wholesale transmission revenues are based on rates and
formulas that are approved by the FERC. Most of NU’s wholesale
transmission revenues are collected through a combination of the RNS
tariff and NU’s LNS tariff. NU’s LNS tariff is reset on June 1st of each
year to coincide with the change in RNS rates. Additionally, NU’s LNS
tariff provides for a true-up to actual costs, which ensures that NU
recovers its total transmission revenue requirements, including the
allowed ROE. Through December 31, 2004, this true-up has resulted
in the recognition of a $4.6 million regulatory liability for refund to
electric distribution companies, including CL&P, PSNH and WMECO.
On June 14, 2004, the transmission segment reached a settlement
agreement with the parties to its rate case, which allows NU to implement
formula-based rates as proposed with an allowed ROE of 11.0 percent.
On September 16, 2004, the FERC approved the settlement agreement.
The retroactive impact of the change in ROE from 11.75 percent to
11.0 percent reduced earnings by $1 million and $0.1 million, in 2004
and 2003, respectively. Effective February 1, 2005, the 11.0 percent ROE
was increased to the aforementioned 12.8 percent ROE.
On February 1, 2005, consistent with its tariff, NU’s transmission
segment implemented an increase to its transmission tariff that is
expected to increase 2005 revenues by approximately $8 million over
2004 transmission revenues.
A significant portion of NU’s transmission businesses’ revenue is from
charges to NU’s electric distribution companies CL&P, PSNH and
WMECO. These companies recover transmission charges through rates
charged to their retail customers. WMECO has a rate tracking mechanism
to track transmission costs charged in distribution rates to the actual
amount of transmission charges incurred. The 2004 rates set in the
CL&P distribution rate case contained a level of transmission revenue
sufficient to recover CL&P’s 2004 transmission costs. On February 1,
2005, CL&P filed an application with the DPUC to obtain approval to
defer for future recovery in its retail transmission rate the increased
transmission costs that CL&P is incurring as of February 1, 2005. The
June 1, 2005 PSNH retail rate increase includes revenues to recover
expected transmission costs. Neither CL&P nor PSNH currently have
transmission rate tracking mechanisms that track transmission costs.
LICAP: In March 2004, ISO-NE filed a proposal at the FERC to implement
locational installed capacity (LICAP) requirements. LICAP is an
administratively determined electric generation asset capacity pricing
mechanism intended to provide a revenue stream sufficient to maintain
existing generation assets and encourage the construction of new
generation assets at levels sufficient to serve peak load, plus a reserve
margin and a cushion. In June 2004, the FERC ordered the creation of
five LICAP zones and accepted ISO-NE’s demand curve methodology.
The FERC ordered LICAP to be implemented by January 1, 2006, and
set certain issues pertaining to the demand curve for hearings.
Hearings began at the end of February 2005. A FERC decision is
anticipated in the fall of 2005. Management cannot at this time predict
the outcome of this FERC proceeding.
CL&P, PSNH and WMECO will incur LICAP charges. Because southwest
Connecticut is a constrained area with insufficient generation assets,
CL&P could incur LICAP costs totaling several hundred million dollars.
These costs would be recovered from CL&P’s customers through the
FMCC mechanism. PSNH and WMECO will also recover these costs
from customers.
Connecticut — CL&P:
Public Act No. 03-135 and Rate Proceedings: On June 25, 2003, the Governor
of Connecticut signed into law Public Act No. 03-135 (the Act) which
amended Connecticut’s 1998 electric utility industry legislation. The
Act required CL&P to file a four-year transmission and distribution
plan with the DPUC. On December 17, 2003, the DPUC issued its final
decision in the rate case.
CL&P filed a petition for reconsideration of certain items in the final
decision on December 31, 2003. The DPUC issued a final decision on
the petition on August 4, 2004. The final decision authorized CL&P to
use existing CTA overrecoveries in lieu of an increase in rates to recover
approximately $24 million, which is the net present value of the
$32 million sought in the reconsideration. The final decision had a
2004 positive pre-tax impact of $11.5 million ($6.9 million after-tax) on
CL&P. The remaining amount of $12.5 million is being amortized over
four years beginning August 1, 2004 as an increase to revenues as the
related costs to be recovered are incurred.
Under the Act, CL&P is allowed to collect a fixed procurement fee of
0.50 mills per kWh from customers who purchase TSO. One mill is
equal to one-tenth of a cent. That fee can increase to 0.75 mills if
CL&P outperforms certain regional benchmarks. The fixed portion
of the procurement fee amounted to approximately $12 million
(approximately $7 million after-tax) for 2004. On September 15, 2004,
CL&P submitted to the DPUC its proposed methodology to calculate
the variable portion (incentive portion) of the procurement fee. On
November 18, 2004 the DPUC suspended this proceeding and has
not indicated when the schedule will be resumed. The variable portion
of the procurement fee has not yet been reflected in earnings.
Retail Transmission Rate Filing: On February 1, 2005, CL&P filed an application
with the DPUC to obtain approval to defer for future recovery in its
retail transmission rate the increased transmission costs that CL&P
is incurring as of February 1, 2005. If the DPUC does not approve this
deferral, CL&P’s application provides for an alternate proposal to
increase its retail transmission rate to recover an additional $7.6 million
on an annual basis, effective February 1, 2005. Under this proposal
the increase would equal $0.00031 per kWh, and would represent
approximately a 0.2 percent increase in overall rates as of February 1, 2005.
Hearings in this docket have not been scheduled.
CTA and SBC Reconciliation: The CTA allows CL&P to recover stranded costs,
such as securitization costs associated with the rate reduction bonds,
amortization of regulatory assets, and independent power producer
(IPP) over market costs, while the SBC allows CL&P to recover certain
regulatory and energy public policy costs, such as public education
outreach costs, hardship protection costs, transition period property
taxes, and displaced worker protection costs.