Terrance G. Howson
EXHIBIT
99.2
Vice
President
Investor Relations
FirstEnergy Corp.
76 S. Main Street
Akron, Ohio 44308
Tel 973-401-8519
April 10, 2006
TO
THE INVESTMENT COMMUNITY
:
1
As
detailed in today’s attached news release, Metropolitan Edison Company
(“Met-Ed”) and Pennsylvania Electric Company (“Penelec”), collectively the
“Companies”, today filed a transition rate plan (“Transition Plan”),
including requests for general rate increases, with the Pennsylvania Public
Utility Commission (“PUC”). This letter provides additional details about
today’s filing.
Background
The
last
retail base rate cases that included combined generation, transmission and
distribution service rates were based on a 1992 rate fililng for Met-Ed and
a 1986 rate filing for Penelec. In 1998, pursuant to the restructuring of
the electric utility industry in Pennsylvania through the Electricity Generation
Customer Choice and Competition Act (“Competition Act”), the Companies’ rates
were capped and unbundled to separate the generation rate from the transmission
and distribution rates. At that time, the Companies each became an
electric distribution company (“EDC”) as defined by the Competition Act.
Under
the Competition Act, non-regulated electric generation suppliers (“EGSs”) are
encouraged to furnish generation service to retail customers in
Pennsylvania. Generation default service to retail customers not served by
an EGS is still available from their EDCs under the provider of last resort
(“POLR”) provisions of the Competition Act.
The
Competition Act required company-specific restructuring plans to be implemented
for each electric utility consistent with the Competition Act’s
provisions. The Companies’ plan for transitioning retail customers to
market-based generation rates was established in 1998 through a PUC order
approving a restructuring settlement (“1998 Plan”). Among other
provisions, the 1998 Plan provided for at least 80% of the Companies’ POLR
customers to move to a competitive default service (“CDS”) provider by mid-2003
for their generation service, but that never occurred due to circumstances
beyond the Companies’ control. As a result, the Companies have borne the
costs and risks of providing ongoing generation service for virtually 100%
of
their POLR load, instead of the anticipated 20%. This generation service
is being provided at an extremely low capped generation rate, which is only
about 50% of the current and projected competitive market rates for generation
service in the Companies’ service territories.
______________________________________
1
Please see the forward-looking statements at the end of this
letter.
The
1998
Plan extended the Companies’ T&D rate cap through year-end 2004 and extended
the generation rate cap through year-end 2010, five years beyond the statutory
generation rate cap imposed by the Competition Act that expired at year-end
2005. Additionally, the 1998 Plan provided for recovery of transition or
stranded costs through a competitive transition charge (“CTC”) and provided for
the deferral and recovery of stranded costs associated with non-utility
generation (“NUG”) purchase power supply contracts.
A
variety of unanticipated events, changed markets and market conditions, a failed
CDS process, significant federally-imposed transmission cost increases, and
other cost-related issues have resulted in the Companies’ need to file the
Transition Plan, which includes requests for general rate increases. The
elements of the Transition Plan are discussed in the following sections.
Overview
of the Transition Plan
One
of
the purposes of the Companies’ Transition Plan is to restore the intent of the
1998 Plan which has failed to provide for the transition of retail customers
to
market-based generation rates, a failure which has placed the Companies in
a
financial situation that is unreasonable and unsustainable. Were it not
for a deeply discounted power purchase agreement that the Companies have with
FirstEnergy Solutions (“FES”), an affiliated non-regulated company, the
Companies would have already faced serious adverse financial consequences from
supplying generation service to their retail customers at below-market
rates. Additionally, the Transition Plan seeks to recover significant
federally-imposed transmission cost increases, fully recover all of the
PUC-approved costs related to the NUG contacts, and provide relief for other
inflationary cost increases.
The
comprehensive Transition Plan is a combination of rates, tariffs and accounting
procedures that, taken together, are intended to provide the Companies with
a
reasonable opportunity to earn a fair return, measured in the aggregate, across
all aspects of their utility business: generation supply, retail
transmission and distribution service, and the recovery of PUC-approved
transition costs.
The
Transition Plan has five components:
1. Distribution
Rates
: A distribution rate change and related accounting
procedures that provide a reasonable opportunity for the Companies
to earn a fair return on their utility investments.
2. Transmission
Rates
: A transmission rate change to reflect federally-imposed
transmission-related charges imposed upon the Companies by the PJM
Interconnection (“PJM”) and the expenses associated with managing such costs for
serving their POLR loads.
3. CTC
Rates
: Authorization to accrue a carrying charge on unrecovered
NUG stranded cost balances in order to avoid the need for a current increase
in
Met-Ed’s CTC rate. Absent this authorization, a requested increase in
Met-Ed’s CTC rate to allow it to fully recover its non-NUG stranded cost balance
by the end of 2010, as required under the 1998 Plan.
4. NUG
Cost Recovery Rates
: A change to either NUG accounting or to NUG
cost recovery in order to provide full recovery of NUG costs, either through
current rates or through a deferral including carrying charges.
5. Generation
Rates
: A gradual four-year (2007–2010) transition of customers’
generation rates towards market-based generation rates, as generally
contemplated by the 1998 Plan. This move to market-priced energy purchases
from market suppliers will progressively reduce the current FES contract supply
and subsidy over time.
The Transition Plan
balances stakeholder interests and provides for a paced change in customer
rates
while protecting the financial integrity of the Companies. If approved by
the PUC, the total rate the Companies’ customers would pay for electricity with
the requested increase in 2007 is expected to remain comparable with the average
rates other electric utilities across the state are charging their customers
today.
The following material
provides additional details of the components of the Transition Plan.
Transition
Plan Components
1.
Distribution Rate Relief
: Met-Ed is filing for a reduction
in its distribution rate while Penelec is filing for a modest increase.
Both requests are based on an allowed return on common equity of 12%. The
Companies are also proposing to recover certain highly variable distribution
costs through rate recovery mechanisms, or tariff “riders”, which will permit
better tracking of such costs than if they were included in base rates.
The tariff riders would use deferred cost accounting along with tracking and
“true up” mechanisms so that, ultimately, customers will only pay for the costs
actually incurred. The Companies believe that the use of these tariff
riders will assure sufficient revenue to meet customer service needs while
retaining the ability to earn a fair return.
The
three cost recovery tariff riders are: (1) a rider to track and recover
the cost of storm restoration, (2) a rider to track and recover universal
service costs, including costs to maintain service to economically disadvantaged
customers, and (3) a “government mandate” rider to track and provide for cost
recovery of programs related to utility service that are required by the
government.
2.
Transmission Rate Relief
: Met-Ed’s T&D rate has not
increased in over fourteen years and Penelec’s has not increased in over twenty
years. However, costs have continued to increase during the past two
decades. Among these costs are substantial increases in transmission
charges that the Companies must pay to PJM as the Regional Transmission
Organization (“RTO”) under tariffs approved by the Federal Energy Regulatory
Commission (“FERC”). The following table details the increasing level of
RTO costs and the growing shortfall the Companies are experiencing under their
current tariff rates.
Met-Ed
and Penelec
RTO
Transmission Revenue and Expenses
($
millions)
|
2001
|
2002
|
2003
|
2004
|
2005
|
2006
|
||||||||||||||
|
Transmission
Revenues
|
$
|
47
|
$
|
48
|
$
|
47
|
$
|
50
|
$
|
52
|
$
|
52
|
|||||||
|
Transmission
Expenses
|
|||||||||||||||||||
|
NITS,
Other
1
|
95
|
99
|
92
|
121
|
133
|
140
|
|||||||||||||
|
Congestion
Costs (net)
2
|
6
|
38
|
2
|
18
|
62
|
98
|
|||||||||||||
|
Pretax
Shortfall
|
$
|
(54
|
)
|
$
|
(89
|
)
|
$
|
(47
|
)
|
$
|
(89
|
)
|
$
|
(143
|
)
|
$
|
(186
|
)
|
|
NOTE:
1.
Includes Network Integration Transmission
Service (“NITS”), ancillary services,
scheduling
and dispatch charges from PJM
2
. Reflects increased costs of energy
assessed to PJM market participants based on
LMPs due to
system redispatch during hours when the PJM transmission system
is operating
under constrained conditions.
Consistent with the PUC’s
recent decision in the PPL Electric Utilities Corporation base rate proceeding,
the Companies are requesting the implementation of a transmission service charge
(“TSC”) tariff rider.
The Companies are
proposing a TSC as a transmission rate tracking mechanism that would function
similar to the Energy Cost Rate (“ECR”) utilized prior to restructuring in the
electric industry in Pennsylvania. The TSC will allow the Companies to
recover their FERC-approved transmission costs billed by PJM and the expenses
for managing such costs for serving retail POLR customers. The TSC will
reflect the current level of transmission charges and forecasted POLR sales,
and
will be reconciled annually. The Companies would use deferred cost
accounting, similar to the operation of the ECR.
This transmission cost
recovery approach meets the standard criteria for an appropriate cost-tracking
mechanism – the expense level is easily identifiable and the Companies have
little discretionary control over the size or the timing of the
expenditures. Similar to the distribution tariff riders, the Companies
believe the TSC will assure that they have sufficient revenue to meet customer
service needs while retaining the ability to earn a fair return.
In January, 2005, the
Companies requested PUC permission to defer all FERC-approved PJM transmission
charges that were incremental to the levels reflected in the current tariff
rates. Although the request was for deferral commencing January 1, 2005,
the Companies are not making any ratemaking claim for the 2005 period in the
Transition Plan. However, the Companies are requesting that the actual
2006 incremental expenses be recognized through a ratemaking deferral that
would
be amortized over ten years.
3.
CTC Relief
: Met-Ed’s CTC rate, which recovers NUG and
non-NUG stranded costs, is currently failing to recover all of the non-NUG
stranded costs which the PUC has authorized to be fully recovered by year-end
2010, the end of the current transition period.
2
At
its current rate level, the CTC would have to increase sharply just before
the
end of the transition period unless an alternative recovery plan, as proposed
by
Met-Ed in the Transition Plan, is implemented.
Under the 1998 Plan, the
unamortized non-NUG stranded costs accrue a carrying charge but the unamortized
deferred NUG stranded costs do not. The Companies have the right to
allocate the CTC revenues towards amortizing either of these unrecovered
stranded cost balances and have first allocated the revenues to the deferred
NUG
stranded cost balance since that balance does not accrue a carrying
charge. The Transition Plan requests the PUC to authorize the application
of a carrying charge on any unrecovered NUG stranded cost balance in a manner
parallel to the current treatment of the non-NUG stranded cost balance.
If approved, Met-Ed would allocate the dominant portion of the current CTC
revenues to amortizing the non-NUG balance first. This would fully recover
those costs by the targeted 2010 date without requiring any current rate
increase in the CTC. Of course, the deferred NUG stranded cost balance
would be higher, but those costs would still be recovered by the targeted 2020
date as the NUG contracts expire at various dates prior to 2020. The
benefit of this preferred approach is that there would be no requirement to
increase Met-Ed’s CTC rate as a part of this filing. If this approach is
not acceptable to the PUC, then the Transition Plan reflects an alternative
approach which increases Met-Ed’s CTC rate in order to ensure that all of the
non-NUG stranded costs are fully recovered by year-end 2010.
4.
NUG Cost Recovery
: The current elevated level of market
power prices is preventing the Companies from fully recovering their costs
of
power obtained from NUGs that have PUC-approved purchase power contracts with
the Companies. Under the 1998 Plan, the Companies’ recovery of NUG
stranded costs is based on valuing NUG energy at hourly locational marginal
market prices and associated capacity costs (collectively, “LMP”). The
Companies are not proposing to disturb that stranded cost provision of the
1998
Plan. However, with sustained escalation of market prices, the Companies
are no longer recovering all of their NUG costs under this approach. The
1998 Plan allows the Companies to defer, as stranded costs for future collection
from customers, the excess of the NUG contract cost over the LMP. But
since the LMP is currently above the POLR rate, the Companies are not collecting
the difference between the LMP and their POLR rate. This result is
contrary to federal and state law requiring full cost recovery for the
Companies’ NUG power purchase costs.
__________________________
2
Met-Ed’s
deferred NUG stranded costs are to be recovered by 2020 under the 1998 Plan.
Penelec’s initial non-NUG stranded costs were fully recovered by the net
generating plant divestiture
proceeds.
The Transition Plan
proposes three approaches for complete NUG power supply cost recovery. The
first, and preferred, approach is to create a new regulatory asset based on
a
deferral of the difference between the generation rate and the LMP for energy
supplied by NUGs. Under this deferral alternative, the Companies would
recover the amounts deferred from 2007 through 2010, and thereafter as long
as
the NUG output is used to supply POLR load, including an appropriate carrying
charge commencing at such time when the Companies seek and receive approval
for
a reduction in the CTC charges as a result of the expiration of existing NUG
contracts. At such time, the difference between the prior CTC charge and
the newly-reduced CTC charge is expected to be available to provide a revenue
stream to the Companies to recover the accumulated deferred balance through
a
separate surcharge mechanism. The second alternative method is to
currently recover the presently unrecovered difference between the NUG values
based on LMP and the generation rate through a separate reconcilable rider-based
charge. The rider would use deferred cost accounting and be reconciled on
an annual basis. This alternative would require a current incremental revenue
increase since the increased NUG costs would be recovered currently instead
of
deferred for future recovery. In the event that the PUC rejects the
deferral approach or the reconcilable rider, the Companies are requesting as
a
third alternative, the establishment of a fixed base rate charge sufficient
to
recover the 2006 test year shortfall. The first alternative – the
deferral approach – is preferable because it would avoid such a current revenue
increase.
3
Failure to recover all
of
the NUG purchase power contract costs is contrary to the language in each NUG
contract, contrary to the related PUC orders requiring full and current recovery
of NUG contract costs, and contrary to portions of Public Utility Regulatory
Policies Act of 1978 (“PURPA”) and the Pennsylvania Public Utility Code.
Any of the three approaches will insure full recovery, although the Companies
prefer the first approach which does not require a current increase in
customers’ rates.
5.
2007-2010 Generation Rates
:
The 1998 Plan required the
Companies to auction their generation plant assets for sale to the highest
bidder and to credit customers with all net divestiture proceeds, thereby
reducing customers’ obligations to pay for stranded costs.
Prior to the final
divestiture arrangements agreed to under the 1998 Plan, the Companies had begun
to reserve rights to some of the output from the generation assets they intended
to sell. However, the 1998 Plan prohibited any further efforts to secure
such rights. As the PUC specifically noted in its Order on the divestiture
results, the Companies were prohibited from placing puts, calls or other options
in place as a condition of the divestiture process. As a result, the
Companies were not permitted to pursue any rights that could have impaired
or
reduced the generation assets’ fair market value and, thus, reduce the
divestiture-driven credits to customers, even though such reservations would
have assisted with ongoing POLR service arrangements. The 1998 Plan
balanced these considerations by weighing in favor of maximizing
post-divestiture credits to customers and relying on the CDS program to satisfy
the Companies’ POLR obligations, recognizing that the generation rates were
subject to increases, if necessary, in order to conduct a successful CDS
program.
The 1998 Plan required
the
Companies’ POLR service obligations to be addressed through the CDS program,
under which POLR service to customers “shall be provided via competitive
bid”. Customers were to be assigned to a CDS provider, commencing June 1,
2000. Over a four-year period it was intended that at least 80% of the
Companies’ retail customer load was to be assigned to one or more CDS
providers. To the extent CDS could not be obtained for customers at the
original capped generation rates under the 1998 Plan, the Companies had
authorization to apply to the PUC on an expedited basis to raise the generation
rate cap level. The Companies agreed to retain only 20% of the POLR
load.
______________________
3
To
illustrate, assume that the generation rate is 4.1¢/kWh, LMP is 6.0¢/kWh, and
the NUG contract price is 7.0¢/kWh. Currently the Companies report revenues of
4.1¢/kWh, expenses of 6.0¢/kWh, and a deferred stranded NUG cost of 1.0¢/kWh,
resulting in a pretax loss of 1.9¢/kWh. Under the preferred approach, revenues
are still 4.1¢/kWh and expenses are 6.0¢/kWh. A NUG Service regulatory asset
deferral is recorded equal to 1.9¢/kWh, and the deferred NUG stranded cost
expense remains at 1.0¢/kWh. Under either alternative method, a revenue increase
of 1.9¢/kWh would eliminate the current loss and maintain the NUG stranded cost
deferral of 1.0¢/kWh.
The CDS portion of the
1998 Plan was implemented but it failed to achieve its intended results.
No bids were ever submitted to provide CDS service to any POLR customer, and
the
PUC eventually issued an order permitting the Companies to withdraw from the
CDS
program. While the failure of the CDS program was completely outside of
the Companies’ control, it left the Companies with the entire POLR load.
This increased risk is a financial burden the Companies never agreed to bear
at
the current POLR rate levels.
The Companies filed for
a
generation rate increase in 2001 and received substantial recommended rate
relief from the presiding administrative law judge in the proceeding.
Subsequently, the Companies and most of the other case participants agreed
on a
settlement that avoided a generation rate increase by recognizing the Companies’
actual ongoing POLR costs through ratemaking deferrals and a reallocation of
CTC
revenues. Although the PUC approved that settlement, it was overturned by
the Pennsylvania Commonwealth Court upon appeal.
Subsequent to the 2001
FirstEnergy / GPU merger, the Companies have received substantial assistance
in
serving their POLR loads through a voluntary wholesale power supply agreement
with FES. In recent years, the contract provides that FES will supply all
of the Companies’ POLR needs that are not being “self-supplied” by the Companies
themselves through either the NUG contracts or through bilateral supply
agreements between the Companies and non-affiliated suppliers. Under the
agreement FES has been providing power to the Companies at the current capped
generation rate, which is a deep discount from current market prices. For
example, FES provides power to the Companies at approximately $41.50 per
MWh
4
,
compared to current energy prices at about twice that price. The FES wholesale
agreement has been shielding the Companies from the losses they would have
incurred had they purchased power at the high market prices that have prevailed
in recent years, while charging their customers what has turned out to be an
unfairly low generation rate. Since FES faces the same high market prices,
this arrangement has resulted in FES, and therefore FirstEnergy shareholders,
effectively subsidizing the Companies and their POLR customers.
FES has notified the
Companies that it cannot continue indefinitely to provide this subsidy to the
Companies at current levels. Consequently, the supply agreement between
FES and the Companies has been modified such that FES has indicated a
willingness to continue to subsidize the POLR costs for the Companies, in
decreasing amounts, consistent with the Transition Plan. Specifically, the
supply agreement now requires the Companies to procure power supplies for their
POLR customers, exclusive of the FES supplies, totaling approximately 32% of
the
non-committed supplies between December 1, 2006 and December 31, 2007. For
these purposes, committed supplies include NUG purchase power contracts, owned
generating facilities, other purchase power contracts and distributed
generation. FES will consider a similar supply arrangement with the
Companies after 2007 but only if the Companies procure power supplies for their
POLR customers, exclusive of the FES supplies, totaling approximately 64% in
2008, 83% in 2009 and 95% in 2010 of the non-committed supplies in those
respective time periods. This modified FES supply agreement is reflected
in the Transition Plan and provides a stepped exit strategy over years 2007
through 2010, to gradually eliminate the current FES power supply subsidy.
The unit price at which FES sells power to the Companies will not change under
the modified supply agreement.
__________________________
4
The
Companies’ retail price is about $46 per MWh due to gross receipt taxes and
distribution system line losses.
The Transition Plan filing
replaces the failed and unworkable retail CDS program with a wholesale Request
for Proposal (“RFP”) process for procuring a portion of the Companies’ POLR
supply requirements. The RFP process will acquire power for the Companies
starting December 1, 2006 through year-end 2010. It is anticipated that
the Transition Plan will also continue to provide customers the full benefit
of
low-cost power supplies through the bilateral contracts the Companies have
procured with unaffiliated suppliers to serve their POLR loads. This
blended supply approach provides moderately stepped increases in generation
rates for customers over time, rather than an inevitable large step increase
to
full market prices in 2011.
The Companies’ POLR energy
supply for 2007 through 2010 will be a blend from four sources:
- Market-priced power procured through the RFP process,
- FES-supplied power,
- NUG supply, and
- Committed supply contracts from non-affiliated third party suppliers.
The following table
details this four-part supply. The 2006 FES supply reflects the estimated
supply from FES for the Companies’ POLR requirements net of the Companies’ NUG,
committed supplies, and a small amount of market power supplied in December
through the RFP process.
Met-Ed
and Penelec
POLR
Energy Supply
(thousand
GWh)
|
2006
|
2007
|
2008
|
2009
|
2010
|
||||||||||||
|
Market
Power (RFP)
1
|
0.3
|
2.8
|
6.1
|
11.9
|
14.2
|
|||||||||||
|
FES
Supply
|
8.0
|
6.0
|
3.3
|
2.4
|
0.8
|
|||||||||||
|
NUGs
|
5.3
|
5.3
|
5.2
|
5.2
|
5.0
|
|||||||||||
|
Committed
Supply
2
|
16.2
|
15.9
|
15.9
|
11.5
|
11.5
|
|||||||||||
|
Total
POLR Requirements
|
29.8
|
30.0
|
30.5
|
31.0
|
31.5
|
|||||||||||
NOTE:
1.
Reflects Market Power in 2006 only for
December.
2.
Includes
Met-Ed’s York Haven hydro
output.
Based on the Companies’
current estimate of forward
energy prices in their regions, the following table
details the estimated change in the generation rate over time as the various
supply sources are blended into the Companies’ generation tariff rate.
Because of the FES supply and the favorable existing supply arrangements with
non-affiliated suppliers, the proposed generation rate is expected to remain
below the currently anticipated full market price.
Met-Ed
and Penelec
Proposed
Generation Rate
(cents
per kWh)
|
2006
|
2007
|
2008
|
2009
|
2010
|
||||||||||||
|
Proposed
Generation Rate
|
4.6
|
5.5
|
6.2
|
7.1
|
7.5
|
|||||||||||
|
Estimated
Power Costs
|
||||||||||||||||
|
Retail
Market Price
|
9.5
|
8.9
|
8.4
|
8.4
|
8.0
|
|||||||||||
|
FES
& Existing Contracts
|
4.0
|
4.0
|
4.0
|
4.1
|
4.1
|
|||||||||||
The proposed RFP process
provides a reasonable plan to protect customers from rate shock in 2011 and
to
flow through to them the benefits of lost-cost POLR power supplies, while also
preserving the financial integrity of the Companies.
As an additional customer
protection, the Transition Plan also includes a rate cap on the proposed
generation rate as detailed in the following table:
Met-Ed
and Penelec
Proposed
Generation Rate Cap
1
(cents
per kWh)
|
2007
|
2008
|
2009
|
2010
|
||||||||||
|
Met-Ed
Generation Rate Cap
|
5.7
|
6.5
|
7.5
|
7.8
|
|||||||||
|
Penelec
Generation Rate Cap
|
5.4
|
5.9
|
6.8
|
7.1
|
|||||||||
NOTE:
1.
The generation rate cap is
subject to certain exceptions such as gross receipts
tax increases and committed supplier defaults, and certain
conditions, such
as
FES being permitted to participate in the RFP process and PUC
approval
of
the timing of the supply procurement process.
This generation rate cap
represents the maximum customer generation rate level even if the cost of the
RFP-supplied power would produce a blended generation rate, and cost to the
Companies, in excess of the capped level.
Transition
Plan
Customer Impacts (2007)
The following revenue
and
customer cost increase amounts combine all five components of the Transition
Plan. The values in the “preferred” column reflect approval of the
requested accounting procedures discussed in this letter. The values in
the “alternative” column show the requested revenues assuming the accounting
modifications are not approved, and instead, rates are required to be adjusted
to provide for appropriate cost recovery:
Financial
Impacts
In general, it is
anticipated that the revenue changes in the Distribution, Transmission, and
NUG
Cost Recovery
5
categories will directly impact the Companies’ earnings on an after-tax
basis
6
.
Changes to the CTC revenue levels do not generally directly impact
earnings. The generation revenue increases are offset by an equal increase
in energy expenses as customers are transitioned towards market-based energy
prices.
FES is expected to see
an
earnings benefit related to the transition of energy sales from the Companies
at
a price of approximately $41.50 per MWh to the sale of those MWhs at a
market-based price.
Selected
Filing
Data
Some selected filing data
for the Companies is attached to this letter as Exhibit 1.
___________________________
5
Although
the NUG Cost Recovery category shows zero revenue in the “preferred” column, the
earnings impact would be the same as the “alternative” column (revenue of $43
million for Met-Ed and $49 million for Penelec) since the preferred approach
would defer the expenses that would be covered by the revenue increase in
the
alternative approach.
6
The
revenues in the table include a 5.9% Pennsylvania gross receipts tax. The
combined Pennsylvania state and federal income tax rates are 41.5%. Included
in
the distribution revenue requirements are increased funding amounts for the
Universal Service Programs (approximately $5 million for Met-Ed and $9 million
for Penelec). Revenues associated with these dollar amounts would have a
matching incremental expense increase and would not produce an incremental
earnings impact.
The Hearing
Process
Following
today’s filing, we expect the PUC to assign an administrative law judge (“ALJ”)
to hear our case and other parties will have the opportunity to
intervene. The ALJ will schedule a pre-hearing conference and
set the schedule for discovery, hearings and the briefing period. At the
end of that process, the ALJ will issue a recommended decision to the PUC and
then the PUC will issue a final order. We expect this process to be
completed in a timeframe that should result in a PUC order early in the first
quarter of 2007 although no assurance can be given that this timeframe will
be
met. As in all of our contested regulatory proceedings, we will remain
open to the possibility of a settlement by working to find common ground among
the parties.
Summary
In
prior regulatory orders, the PUC has emphasized that Pennsylvania’s electric
industry restructuring process has involved, in the case of each utility, a
delicate balancing of often competing interests. Individual circumstances,
and inherent differences among Pennsylvania’s electric utilities, call for
flexibility in structuring an appropriate remedy for a particular utility to
address problems that have emerged.
There
is little doubt that the Companies are unique within Pennsylvania with respect
to their restructuring plans. Customers received the considerable benefit
of all of the net gains realized from the divestiture of the Companies’
generation assets while the Companies were to receive certain benefits and
protections expected to result from the 1998 Plan. Had the 1998 Plan
worked as intended, at least 80% of the Companies’ POLR load would be at or near
market-based generation rates today. As discussed in this letter, the 1998
Plan has not worked as intended. Consequently, mid-course adjustments must
be made at this time to give effect to the intent of the 1998 Plan, provide
a
transition to market-based generation rates, ensure full and timely recovery
of
CTC non-NUG stranded costs and NUG power supply costs, recover the large
increase in RTO costs, and allow the Companies to earn a reasonable return
in
order to remain financially viable and to be able to economically finance their
necessary infrastructure expansions and system improvements.
Today’s
filed comprehensive Transition Plan is a carefully balanced combination of
rates, tariffs and accounting procedures that, when taken together, achieves
the
above objectives. The Transition Plan is expected to allow our customers
to continue to pay below-market prices for generation through 2010, and the
total rate our customers would pay for electricity with the requested increase
in 2007 would remain comparable to the average rates other electric utilities
across the state are charging their customers today.
If
you have any questions concerning information in this update, please call Kurt
Turosky, Director of Investor Relations, at (330) 384-5500, or me at (973)
401-8519.
Very truly yours,
T
errance
G. Howson
Vice
President
- Investor Relations
Exhibit 1
Metropolitan
Edison Company
Selected
Normalized Filing Data
Ratemaking Test
Year:
Calendar Year 2006
Retail
Sales:
13,961 GWh
Ratebase
:
$1,291 million
Requested Return
on
Common Equity:
12%
Capital Structure
and Cost of Capital:
|
Met-Ed
|
||||||||||
|
Capital
|
Cost
|
Weighted
|
||||||||
|
Ratios
|
Rate
|
Cost
|
||||||||
|
Long-Term
Debt
|
51
|
%
|
6.09
|
%
|
3.11
|
%
|
||||
|
Common
Equity
|
49
|
12.00
|
%
|
5.88
|
||||||
|
Total
|
100
|
%
|
8.99%
1
|
|||||||
NOTE:
1.
The weighted cost rate of return is applicable to the $1,000 million
of
distribution rate base.
No
change has been requested
regarding the 10.4% pretax carrying charge applicable to the
$291
million of
non-NUG stranded cost rate base.
Pennsylvania
Electric Company
Selected
Normalized Filing Data
Ratemaking Test
Year:
Calendar Year 2006
Retail
Sales:
14,208 GWh
Ratebase
:
$1,095 million
Requested Return
on
Common Equity:
12%
Capital Structure
and Cost of Capital:
|
Penelec
|
||||||||||
|
Capital
|
Cost
|
Weighted
|
||||||||
|
Ratios
|
Rate
|
Cost
|
||||||||
|
Long-Term
Debt
|
51
|
%
|
6.56
|
%
|
3.35
|
%
|
||||
|
Common
Equity
|
49
|
12.00
|
%
|
5.88
|
||||||
|
Total
|
100
|
%
|
9.23
|
%
|
||||||
Forward-Looking
Statements
This investor letter
includes forward-looking statements based on information currently available
to
management. Such statements are subject to certain risks and uncertainties.
These statements typically contain, but are not limited to, the terms
"anticipate," "potential," "expect," "believe," "estimate" and similar words.
Actual results may differ materially due to the speed and nature of increased
competition and deregulation in the electric utility industry, economic or
weather conditions affecting future sales and margins, changes in markets for
energy services, changing energy and commodity market prices, replacement power
costs being higher than anticipated or inadequately hedged, the continued
ability of our regulated utilities to collect transition and other charges
or to
recover increased transmission costs, maintenance costs being higher than
anticipated, legislative and regulatory changes (including revised environmental
requirements), and the legal and regulatory changes resulting from the
implementation of the Energy Policy Act of 2005 (including, but not limited
to,
the repeal of the Public Utility Holding Company Act of 1935), the uncertainty
of the timing and amounts of the capital expenditures (including that such
amounts could be higher than anticipated) or levels of emission reductions
related to the Consent Decree resolving the New Source Review litigation,
adverse regulatory or legal decisions and outcomes (including, but not limited
to, the revocation of necessary licenses or operating permits, fines or other
enforcement actions and remedies) of governmental investigations and oversight,
including by the Securities and Exchange Commission, the United States
Attorney's Office, the Nuclear Regulatory Commission and the various state
public utility commissions as disclosed in our Securities and Exchange
Commission filings, generally, and with respect to the Davis-Besse Nuclear
Power
Station outage and heightened scrutiny at the Perry Nuclear Power Plant in
particular, the timing and outcome of various proceedings before the
Pennsylvania Public Utility Commission, including the transition rate plan
filings for Met-Ed and Penelec, the continuing availability and operation of
generating units, the ability of our generating units to continue to operate
at,
or near full capacity, our inability to accomplish or realize anticipated
benefits from strategic goals (including employee workforce initiatives), the
anticipated benefits from our voluntary pension plan contributions, our ability
to improve electric commodity margins and to experience growth in the
distribution business, our ability to access the public securities and other
capital markets and the cost of such capital, the outcome, cost and other
effects of present and potential legal and administrative proceedings and claims
related to the August 14, 2003 regional power outage, circumstances which may
lead management to seek, or the Board of Directors to grant, in each case in
its
sole discretion, authority for the implementation of a share repurchase program
in the future, the risks and other factors discussed from time to time in our
Securities and Exchange Commission filings, and other similar factors.. We
expressly disclaim any current intention to update any forward-looking
statements contained herein as a result of new information, future events,
or
otherwise.