<PAGE> 1
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 8-K
CURRENT REPORT
PURSUANT TO SECTIONS 13 OR 15(D) OF THE
SECURITIES AND EXCHANGE ACT OF 1934
Date of Report (Date of earliest event reported): July 15, 1999
<TABLE>
<CAPTION>
Commission Registrant, State of Incorporation I.R. S. Employer
File Number Address and Telephone Number Identification Number
- ----------- ---------------------------- ---------------------
<S> <C> <C>
1-13895 Conectiv (a Delaware Corporation) 51-0377417
800 King Street
P.O. Box 231
Wilmington, Delaware 19899
Telephone (302) 429-3114
1-3559 Atlantic City Electric Company 21-0398280
(a New Jersey Corporation)
800 King Street
P.O. Box 231
Wilmington, Delaware 19899
Telephone (302) 429-3114
</TABLE>
<PAGE> 2
Item 5. OTHER EVENTS
On June 9, 1999, Conectiv's subsidiary, Atlantic City Electric
Company ("Company"), entered into a Stipulation of Settlement ("Stipulation")
with some of the parties to the Company's stranded costs, unbundled rates, and
restructuring proceedings pending before the New Jersey Board of Public
Utilities ("NJBPU") and filed the Stipulation with NJBPU. On July 15, 1999, the
NJBPU approved, with modifications, the Company's Stipulation and issued a
summary order ("Summary Order") detailing the modifications to the original
Stipulation. The NJBPU stated that a more detailed order would be issued at a
later date.
In its Summary Order, the NJBPU directed the Company to
implement a five percent aggregate rate reduction effective August 1, 1999. As
part of the initial five percent aggregate rate reduction, the NJBPU set the
Company's system average distribution rate at 2.1384 cents per kwh. The Company
also must implement at least an additional two percent rate reduction by January
1, 2001, and by August 1, 2002 an additional rate reduction such that rates are
reduced a total of ten percent, as compared to rates in effect as of April 30,
1997. The Company estimates that the initial rate reduction will result in about
a $50 million reduction in revenues. However, the ultimate impact on the net
income of the Company will depend upon the nature and extent of cost reductions
that may be realized by the Company.
The NJBPU Summary Order also established minimum initial shopping
credits for customers who choose an alternative electric supplier, from a system
average 5.27 cents per kilowatt hour, effective August 1, 1999, to a system
average of 5.48 cents per kilowatt hour in 2003. These shopping credits, based
on the charges for power supply and transmission, include charges by the Company
for Basic Generation Service ("BGS") to be provided retail customers who do not
have a competitive electric power supplier. The NJBPU Summary Order also
approved the deferral mechanism contained in the Company's Stipulation, in order
to enable the Company to meet and sustain the rate reductions ordered by the
NJBPU. The deferral mechanism provides for the accumulated deferral of costs and
application of certain over-recovery credits, for ultimate recovery of the
resultant net deferred balance, during the four years after the initial
four-year transition period ("Transition Period") commencing August 1, 1999. The
NJBPU approved certain rates of return to be applied to the deferred balances.
Also under the Stipulation, the Company will divest itself of its
nuclear and fossil fuel baseload units and transfer the remaining generating
units to a non-utility affiliated company at the net book value. As a condition
to the transfer and for the duration of the Transition Period, the NJBPU Summary
Order requires that if any transferred asset is sold to an unaffiliated company,
the net after-tax gain over the adjusted book value would be shared equally
between the Company and customers. The NJBPU Summary Order concurred with the
Stipulation that the Company shall be permitted the opportunity to recover 100%
of the net stranded costs related to the generation units to be divested. The
Summary Order further concurred with the Stipulation that the Company may also
2
<PAGE> 3
recover 100% of the stranded costs associated with power purchased from
Non-Utility Generators ("NUG's"). The NJBPU Summary Order also provided for the
securitization of amounts used to effect potential buyouts or buydowns of
contracts with NUG's as well as limited incentives for the Company in the event
of such contract restructuring.
The NJBPU Summary Order does not provide for recovery of stranded costs
associated with the Company's transfer of generating units to a non-utility
affiliated company. As previously reported in the Company's 1999 first quarter
Form 10-Q, the Company expects during 1999 an extraordinary charge to earnings
of approximately $50 million to $75 million as a result of this transfer.
Conectiv's related news release, the NJBPU Summary Order and
Atlantic City Electric Company's Stipulation of Settlement are annexed as
exhibits.
Item 7. FINANCIAL STATEMENTS PRO FORMA FINANCIAL INFORMATION AND EXHIBITS
(c) Exhibits
1. Conectiv News Release, dated July 15, 1999
2. NJBPU Summary Order, dated July 15, 1999
3. Atlantic City Electric Company Stipulation of Settlement as
filed with the NJBPU, dated June 9, 1999
3
<PAGE> 4
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned hereunto duly authorized.
CONECTIV
Atlantic City Electric Company
Date: July 22, 1999 /s/Philip M. Reese
Treasurer
<PAGE> 5
EXHIBITS TO BE FILED BY EDGAR
(c) Exhibits
1. Conectiv News Release, dated July 15, 1999
2. NJBPU Summary Order, dated July 15, 1999
3. Atlantic City Electric Company Stipulation of Settlement as filed
with the NJBPU, dated June 9, 1999
<PAGE> 1
EXHIBIT C-1
[CONECTIV LOGO]
For immediate release
July 15, 1999
For more information, call
Betty Kennedy (609) 625-5567
CONECTIV RESTRUCTURING DECISION ANNOUNCED
Mays Landing, N.J. - Conectiv Executive Vice President Tom Shaw said the
decision made today by the Board of Public Utilities regarding the company's
restructuring proposal benefits New Jersey customers with rate reductions
beginning Aug. 1 and sets the stage for real competition to develop.
"The announced Board ruling appears to balance the interests of our customers,
shareholders and employees," said Shaw. "We realize that the mandated rate
reductions and increase in the shopping credit allowance are a part of the
series of challenges that our company must meet as our industry becomes fully
competitive."
"We believe the ruling gives us the framework to successfully meet those
challenges," he added.
The BPU decision includes a revamping of Conectiv's 10-percent rate reduction
and an increase in the residential shopping credits. Both were previously
negotiated with groups representing the interests of New Jersey business
consumers, non-regulated generators and retail power suppliers.
(more)
<PAGE> 2
Page 2 /Conectiv Restructuring Decision Announced
The Board mandated an initial 5-percent rate reduction effective August 1, at
least an additional 2-percent rate reduction by Jan. 1, 2001, and 3 percent by
August 1, 2002, totaling 10 percent within three years. The rate reductions must
be sustained through July 31, 2003. Combined with the gross receipts and
franchise tax reduction, customer rates will be reduced by approximately 15
percent within four years. It is estimated the initial rate reduction will
result in about a $50 million reduction in revenues.
"With this Board decision, the path of the electric utility industry
restructuring is clearer. This clarity should help Conectiv go forward to
implement its overall business strategy. We believe the successful
implementation of that strategy and the continued effort of our management and
workforce to look for ways to cut costs and increase productivity should enable
us to overcome the loss of revenue," Shaw said.
"We are committed to providing our customers these significant savings, while
maintaining safe, reliable, quality service," he added.
The BPU established shopping credits higher than those proposed in the
settlement. The BPU ruling establishes average shopping credit "floors" of 5.27
cents per kilowatt hour effective Aug. 1, 1999, 5.31 cents in 2000, 5.37 cents
in 2001, 5.42 in 2002 and 5.48 in 2003. These shopping credits will be the
highest in New Jersey; in addition they may increase based on the market price
of energy.
"While customers will be able to shop for their energy suppliers, Conectiv will
continue to deliver that energy, maintain the wires and poles, and provide
emergency service," said Shaw.
(more)
<PAGE> 3
Page 3 /Conectiv Restructuring Decision Announced
The ruling allows Conectiv to fully recover approximately $800 million of
stranded costs associated with the non-utility generation contracts. Conectiv
announced in May that it would divest its base-load generating facilities. The
stranded cost associated with the generation stations to be sold, previously
estimated to be about $400 million, will be determined through the sale and also
will be fully recoverable.
The company will transfer its remaining New Jersey generation to an unregulated
subsidiary, and if those facilities are sold within the four-year transition
period, net gains will be shared by customers and shareholders.
In addition, the Board's decision supports full securitization of stranded costs
associated with restructuring or buyout of non-utility generating contracts and
the divested generation.
Conectiv, formed through the merger involving Atlantic Energy, Inc. and Delmarva
Power & Light Company, is the parent company for Conectiv Power Delivery, a
regulated energy provider that provides electric service to almost 1 million
customers, including 480,000 in southern New Jersey.
FORWARD-LOOKING STATEMENTS
The Private Securities Litigation Reform Act of 1995 (the "Litigation
Reform Act") provides a "safe harbor" for forward-looking statements to
encourage such disclosures without the threat of litigation, provided those
statements are identified as forward-looking and are accompanied by meaningful,
cautionary statements identifying important factors that could cause the actual
results to differ materially from those projected in the statement.
Forward-looking statements have been made in this Press Release. Such statements
are based on beliefs of Conectiv's (the "Company's") management ("Management")
as well as assumptions made by and information currently available to
Management. When used herein, the words "will," "anticipate," "estimate,"
"expect," "objective," and similar expressions are intended to identify
forward-looking statements. In addition to any assumptions and other factors
referred to specifically in connection with such forward-looking statements,
factors that could cause actual results to differ materially from those
contemplated in any forward-looking statements include, among others, the
following:
(more)
<PAGE> 4
Page 4/ Conectiv Restructuring Decision Announced
deregulation of energy supply and telecommunications; the unbundling of delivery
services; and increasingly competitive energy and telecommunications
marketplace; results of any asset dispositions; sales retention and growth;
federal and state regulatory actions; future litigation results; cost of
construction; operating restrictions; increased costs and construction delays
attributable to environmental regulations; nuclear decommissioning and the
availability of reprocessing and storage facilities for spent nuclear fuel; and
credit market concerns. The Company undertakes no obligation to publicly update
or revise any forward-looking statements, whether as a result of new
information, future events or otherwise. The foregoing list of factors pursuant
to the Litigation Reform Act should not be construed as exhaustive or as
admission regarding the adequacy of disclosures made prior to the effective date
of the Litigation Reform Act.
www.conectiv.com
###
<PAGE> 1
EXHIBIT C-2
AGENDA DATE: 07/15/99
STATE OF NEW JERSEY
BOARD OF PUBLIC UTILITIES
TWO GATEWAY CENTER
NEWARK NJ 07102
ENERGY
IN THE MATTER OF ATLANTIC CITY ) SUMMARY ORDER
ELECTRIC COMPANY'S RATE )
UNBUNDLING, STRANDED COSTS AND ) BPU DOCKET NOS. E097070455,
RESTRUCTURING FILINGS ) EO97070456, AND EO97070457
(SERVICE LIST ATTACHED)
BY THE BOARD:
This Summary Order memorializes in summary fashion the action taken by
the Board of Public Utilities ("Board") in these matters at its specially-
scheduled July 15, 1999 public agenda meeting with respect to the rate
unbundling, stranded costs and restructuring filings of Atlantic City Electric
Company ("ACE", "Atlantic" or "Company").
The Board will issue a more detailed Decision and Order in these
matters, which will provide a full discussion of the issues as well as the
reasoning for the Board's determinations. These matters come before the Board on
a record developed by Administrative Law Judge ("ALJ") William Gural, who issued
an Initial Decision on August 17, 1998, and hearings conducted before
Commissioner Carmen J. Armenti from April 27, 1998 through May 28, 1998.
Subsequent to the ALJ's Initial Decision and the hearings before Commissioner
Armenti, the Legislature passed and Governor Whitman signed into law on February
9, 1999, the Electric Discount and Energy Competition Act, P.L. 1999, c. 23
("the Act").
Settlement negotiations were conducted among the parties during the
latter part of April, through the early part of June 1999. A comprehensive
settlement was not reached, but on June 9, 1999, a Stipulation was filed by ACE
on behalf of a number of parties to the proceedings ("ACE Stipulation"). The
Board determined to solicit and consider comments on the ACE Stipulation, and
established a comment deadline of June 16, 1999 for comments addressing the ACE
Stipulation, including any alternative settlement proposal(s), and a deadline of
June 18, 1999 for comments addressing any alternative settlement proposal(s). On
June 16, 1999 an alternative joint proposal was submitted by the Division of the
Ratepayer Advocate on behalf of a number of other parties to these proceedings
("RPA Stipulation").
Based on our review of the extensive record in these proceedings, as
well as the comments submitted, the Board is not fully satisfied that either
proposal in its entirety represents an appropriate resolution of these
proceedings. The Board finds the ACE
<PAGE> 2
Stipulation to be overall more financially prudent and consistent with the Act's
requirements and, with the modifications and clarifications set forth
hereinbelow, provides the framework for a reasonable resolution of these matters
based upon the record before us. However, the proponents of the RPA Stipulation
and others have raised a number of legitimate concerns regarding the ACE
Stipulation which merit serious consideration and which, where appropriate, are
addressed by the modifications and clarifications set forth below.
Accordingly, except as specifically noted below, and as will be further
explained in a detailed order which shall be issued, we hereby incorporate by
reference as if completely set forth herein as a fair resolution of the issues
in these proceedings, the elements of the ACE Stipulation and, to the extent the
Initial Decision is inconsistent herewith, it is modified to conform herewith.
The modifications and clarifications to the ACE Stipulation which we
HEREBY ORDER are summarized as follows:
Paragraph 1: The initial aggregate rate reduction, inclusive of all
unbundled rate components, to be implemented effective August 1, 1999
shall be 5% from current rates. The average distribution rate for the
Company effective on August 1, 1999 shall be 2.1384 cents per kwh. The
MTC shall be set as the residual amount necessary to achieve the rate
reduction, after accounting for other unbundled rate components
established pursuant to this Order, including the distribution rate,
regulatory asset charge, state energy taxes including sales and use
tax, corporate business tax and TEFA, societal benefits charge, NNC,
and BGS charge. The DSM and LEAC overrecovery balances, including
accrued interest, shall not be utilized to offset regulatory asset
charges but shall instead be credited to, and become the starting
balance of, the deferred balance established pursuant to paragraph 27.
Effective no later than January 1, 2001 the Company shall implement a
further aggregate rate reduction of at least 2% relative to current
rates (bringing the total rate reduction to at least 7%). However, to
the extent that the Company completes the divestiture of generating
assets and securitization of net owned generation stranded costs, or
successfully completes a NUG contract(s) restructuring, buyout or
buydown and securitization of net NUG stranded costs prior to January
1, 2001, it shall implement a rate reduction reflecting the full
resultant savings no later than the date of the establishment of the
resultant TBC. To the extent that such savings result in the
implementation of a further rate reduction of less than 2%, Atlantic
shall in any event reduce rates effective January 1, 2001 to achieve
the 7% total rate reduction as of that date. To the extent that the
savings resulting from divestiture and securitization of net owned
generation stranded costs, and/or NUG restructuring buyout or buydown
and
DOCKET NOS. EO97070455,
EO97070456, EO97070457
2
<PAGE> 3
securitization exceeds 2%, Atlantic shall implement a rate reduction
beyond 7% to fully pass such savings on to customers, upon the date of
the establishment of the resultant TBC. To the extent that the sum of
the unbundled rate components as of July 31, 2002 exceeds the price cap
resulting from the implementation of a 10% aggregate rate reduction
relative to April 30, 1997 rates, which unbundled rate components are
to reflect any savings which have resulted from the buyout, buydown, or
restructuring and securitization of NUG contracts implemented pursuant
to paragraph 1(c) of the Stipulation, the Company shall, consistent
with the provisions of the Stipulation, achieve effective August 1,
2002 the mandated 10% aggregate rate reduction relative to April 30,
1997 rates.
Paragraph 2: The initial 5% (August 1, 1999) and final 10% (August 1,
2002) rate reductions are required by the Act, and shall not be
contingent upon divestiture and securitization of generation assets.
Paragraphs 5 and 6: The floor residential service ("RS") shopping
credits shall be increased by 0.50 cents per kwh for 1999 and 2000, and
by 0.55 cents per kwh in 2001, 2002 and 2003. The floor shopping
credits for commercial and industrial Secondary and Primary voltage
tariff customers (MGS-Sec, MGS-Pri, AGS-Sec, AGS-Pri, AGT-Sec, AGT-Pri)
shall be decreased in all years by 0.1 cents per kwh.
Paragraph 7: Atlantic shall apply both NUG contract power and
to-be-divested owned generation power (prior to the closure of the sale
of the generation assets) towards the BGS supply requirement, which
power shall be credited at the net BGS price (the floor shopping credit
less transmission cost, sales and use tax, line losses, ancillary
services and capacity reserve margin). Such credited prices shall be
employed for purposes of establishing the level of the NNC and
establishing the level of owned generation revenue requirement recovery
(prior to the completion of divestiture), in accordance with this
Order. Atlantic shall utilize and open competitive bidding process for
BGS supply requirements net of NUG Power and Owned Generation
(Pre-Divesture).
Paragraph 8: The 12 month minimum BGS commitments requirement for
customers returning to BGS supply shall not apply to residential
customers who return to BGS for any reason. However, the Board will
monitor this issue and request related reports from the Company, and
may revisit this issue if gaming occurs, or if it is otherwise
determined by the Board to be appropriate.
DOCKET NOS. EO97070455,
EO97070456, EO97070457
3
<PAGE> 4
Paragraph 9: Modified in accordance with modifications to paragraph 7.
Paragraph 11: We hereby clarify the language to indicate that the Board
is not pre-judging the reasonableness and prudence of the actual
parting contracts or financial instruments that the Company may procure
in accordance with this paragraph, and that any such costs are subject
to Board review and approval.
Paragraph 12: We hereby modify the language as necessary to conform
with the modifications to paragraph 7, and further clarify that
Atlantic shall reserve the right to bid out the BGS obligation net of
NUG power or to sell NUG power to the selected BGS supplier at the net
BGS price.
Paragraph 16: The Board concurs that the Company shall be permitted the
opportunity to recover 100% of its net owned generation stranded costs
(established definitively upon completion of the divsetiture) and NUG
contract costs, however we modify the language only so far as is
necessary to conform with the differing standards for recovery of net
generation stranded costs and 100% recovery of NUG stranded costs
provided in section 13 of the Act.
Paragraph 17: We hereby clarify the language to indicate that the net
book value shall reflect the net investment in each facility,
reflective of the gross investment less depreciation reserve less
accumulated deferred income tax, and investment tax credits if
appropriate, as of the closing date(s), and to clarify that the tax
impacts with respect to taxable gains and/or losses will be considered
in calculating net stranded cost.
Paragraph 18: We hereby modify the language to indicate that while the
Board supports the Company's decision to auction its generation assets,
we are not pre-judging the prudence of Atlantic in implementing the RFP
and selecting a winner bidder(s), and that such final judgement will
come at the conclusion of the separate divestiture proceeding.
Paragraph 19: The Board recognizes the benefit of expediting its review
and approval of divestiture standards, and will endeavor to accomplish
same, but modifies the language to indicate that we cannot be bound at
this time by a specific timetable.
DOCKET NOS. EO97070455,
EO97070456, EO97070457
4
<PAGE> 5
Paragraph 20: The Board recognizes that parting contracts that make
possible or enhance the sale of generating assets can be in the public
interest, but clarify the language as necessary to indicate that the
Board is not pre-judging prudence of actual parting contracts which may
be entered into by Atlantic; such judgement will be rendered after
Board review in the context of the separate divestiture proceeding.
Paragraph 21: The transfer of Deepwater and the combustion turbines
shall occur at a transfer value equal to the net book value of the
assets at the time of the transfer. This amount is approximately $9
million higher than that provided in the Stipulation, is intended to
reflect full and fair compensation for the assets, and will avert the
need for Atlantic to take a write-off prior to the transfer. We further
modify this paragraph such that if within the four year Transition
Period any transferred asset is sold to an unaffiliated company, the
net after tax gain over the adjusted book value will be shared equally
between the Company and customers. Further, as a condition of the
transfer during the transition period, Atlantic's affiliate shall offer
capacity from the transferred units for sale within the PJM control
area at market prices, and if the capacity is sold outside the PJM
control area, the Company's affiliate shall make the capacity subject
to recall by PJM during system emergencies.
Paragraph 22: During the period between August 1, 1999 and completion
of the divestiture of generation assets, MTC revenues shall be applied
to owned generation revenue requirements, including continued
depreciation of assets, and return on investment, operating and
maintenance expenses and fuel expenses, and, between the time of
divestiture closing and time of securitization closing, MTC revenues
shall be applied to provide a return on the net owned generation
stranded cost at 13.0% pre-tax. At time of the termination of the MTC
(upon the establishment of the TBC), total MTC revenues and market
revenues received from the crediting of owned generation power to BGS
in accordance with paragraph 7 (as modified) will be reconciled to the
amounts indicated, including a review of the prudence and
reasonableness of the Company's operation of the units, and the
deferred balance will be reconciled accordingly to reflect a resulting
shortfall or excess.
Paragraph 23: We modify the language to provide that, during the
Transition Period, Atlantic will only retain a portion of savings from
NUG contract buyouts, buydowns or restructurings once the 10% aggregate
rate reduction relative to April 30, 1997 rates is achieved without the
use of cost deferrals. We further clarify the language to indicate that
NUG securitization approval is
DOCKET NOS. EO97070455,
EO97070456, EO97070457
5
<PAGE> 6
contingent upon such NUG contract buyout, buydown or restructuring
being approved by the Board and found to be consistent with the
standards in sections 13 and 14 of the Act.
Paragraph 24: The Board renders no determination at this time with
respect to the securitization of restructuring-related costs of
capital. The recovery of restructuring-related costs of a capital
nature via the MTC shall be subject to a reasonableness and
verification review by the Board, and shall be net of other sources of
recovery towards such costs, including Third Party Supplier Agreement
fees. The rate of return on unamortized restructuring-related costs
collected via the MTC shall be 13.0% pre-tax.
Paragraph 25: The recovery of restructuring-related costs of an
operating nature other than consumer education costs, as listed in
Schedule D, via the MTC shall be subject to reasonableness and
verification review by the Board, and shall be net of other sources of
recovery towards such costs, including Third Party Supplier Agreement
fees.
Paragraph 26: This is not appropriate language for a Board Order. AE
may reserve all its legal rights, however the Board rejects this
paragraph.
Paragraphs 27, 28 and 29: The Board hereby modifies this paragraph to
change references from "Deferred Revenues" to "Deferred Costs," and to
provide, with respect to the rate of return on the Deferred Costs
balance, that on any accrued underrecovery balance up to $50 million,
interest will be accrued at a rate equal to the then-current cost of
medium term debt. On any accrued deferred underrecovery balance amounts
in excess of $50 million, such excess amounts shall accrue interest at
a rate equal to the then-current cost of mid-term debt plus 350 basis
points. The Board further modifies the language to indicate that, while
the Company shall be provided the opportunity to fully recover Deferred
Costs and related interest in accordance with the provisions of the
Stipulation, as modified herein and consistent with the Act, the Board
will not bestow on Atlantic an "absolute right" to such recovery.
Finally, we hereby clarify the language to indicate that final approval
of recoverability of the Deferred Cost balance is subject to Board
review of the prudence and reasonableness of such costs.
Paragraph 30: The Board hereby clarifies the language to indicate that
the Company shall be provided with full and timely recovery of
transition bond charges in conformance with the standards set forth in
sections 14 through 27 of the Act, and that the Company shall be
provided the opportunity for full
DOCKET NOS. EO97070455,
EO97070456, EO97070457
6
<PAGE> 7
recovery of related and applicable taxes via a separate MTC charge with
a term identical to the securitization financing pursuant to the
standards set forth in sections 13 and 14 of the Act.
Paragraph 31: With respect to the securitization of net NUG stranded
costs related to a contract restructuring, buyout or buydown, we hereby
clarify the language to conform with the clarifications rendered in
paragraph 23.
Paragraph 32: The Board will render no determination at this time with
respect to the securitization of restructuring-related costs of
capital.
Paragraph 36: We hereby clarify the language to indicate that
imputation of tax expenses or tax benefits on a utility stand-alone
basis is for ratemaking purposes as it applies to the computation of
divestiture proceeds, MTC revenues, divestiture and NUG buyouts as a
result of these matters only, and that such treatment has no
precedential value with regard to future rate cases pertaining to the
regulated rates of Atlantic.
Paragaph 38: While we recognize the desire for and potential benefit of
expeditious review and approval of NUG contract restructuring, buyout
or buydown proposals, and will make every effort to accomplish same,
the Board cannot be bound at this time to a specific timetable.
Paragraph 43: We clarify the language to indicate that recovery via the
MTC of expenses to redeem or retire outstanding capital in connection
with the recovery of stranded costs is subject to Board review that
such costs have been reasonably and prudently incurred. We also note
that reasonably and prudently incurred capital retirement and
redemption expenses associated with a securitization financing are
included within the definition of bondable stranded costs in the Act
and may therefore be securitized and recovered via the TBC.
Paragraph 44: The Board supports the need for an annual review of the
indicated charges and related deferred costs accruals, and further
notes that periodic true-ups of the TBC are required by the Act. We
clarify, however, that to satisfy the rate reduction provisions of the
Act, the Board may or may not actually adjust the indicated charges
(other than the TBC, and the BGS price as provided in elsewhere in the
Stipulation and in this Order) during the transition period.
Paragraph 47: The Board acknowledges that the Company may reserve its
rights, however we shall not adopt this paragraph.
DOCKET NOS. EO97070455,
EO97070456, EO97070457
7
<PAGE> 8
In summary, subject to the conditions embodied herein, the rate
discounts provided by Atlantic, all stated relative to current rates, shall be
at a minimum as follows:
August 1, 1999 5%
January 1, 2001 7%
August 1, 2002 10.2%
The average shopping credits during the Transition Period shall be, at
a minimum, as follows:
<TABLE>
<CAPTION>
Rate Class 1999 2000 2001 2002 2003
---------- ------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
RS 5.65 5.70 5.75 5.80 5.85
RS-TOU 5.10 5.15 5.20 5.25 5.30
MGS-Sec 5.35 5.40 5.50 5.60 5.70
MGS-Pri 5.18 5.23 5.33 5.43 5.53
AGS-Sec 5.30 5.35 5.45 5.55 5.65
AGS-Pri 5.07 5.12 5.17 5.22 5.27
AGT-Sec 5.05 5.10 5.15 5.20 5.25
AGT-Pri 4.95 5.00 5.00 5.00 5.00
AGT-SubT 4.30 4.30 4.30 4.30 4.30
AGT-Trans 4.25 4.25 4.25 4.25 4.25
TGS 4.30 4.30 4.30 4.30 4.30
SPL/CSL 2.97 3.05 3.07 3.10 3.12
DDC 3.58 3.68 3.71 3.75 3.78
System
Average 5.27 5.31 5.37 5.42 5.48
</TABLE>
Within five (5) business days of the date of this Order, the Company is
HEREBY DIRECTED to submit to the Board a tariff compliance filing addressing the
provisions of this Summary Order, and to submit to the Board schedules that show
all accounting entries that will be required with respect to the transfer of the
combustion turbine and Deepwater generating facilities as a result of this
Order, for both Atlantic and the unregulated affiliate. The Company shall
consult with Staff to assure the adequacy of the required submissions
DATED: 7/15/99 BOARD OF PUBLIC UTILITIES
BY:
/S/ Herbert H. Tate
-------------------
HERBERT H. TATE
PRESIDENT
DOCKET NOS. EO97070455,
EO97070456, EO97070457
8
<PAGE> 9
/s/ Carmen J. Armenti
---------------------
CARMEN J. ARMENTI
COMMISSIONER
/s/ Frederick F. Butler
-------------------
FREDERICK F. BUTLER
COMMISSIONER
ATTEST: /s/ Mark W. Musser
------------------
MARK W. MUSSER
SECRETARY
DOCKET NOS. EO97070455,
EO97070456, EO97070457
9
<PAGE> 1
EXHIBIT C-3
STATE OF NEW JERSEY
BOARD OF PUBLIC UTILITIES
- ------------------------------------
:
I/M/O of the Energy Master Plan : BPU Docket No. EO97070456
Phase II Proceeding to Investigate : OAL Docket No. PUC07311-97
the Future Structure of the :
Electric Power Industry :
(Atlantic City Electric Company) :
Stranded Costs Filing :
:
I/M/O of the Energy Master Plan : BPU Docket No. EO97070455
Phase II Proceeding to Investigate : OAL Docket No. PUC07311-97
the Future Structure of the :
Electric Power Industry :
(Atlantic City Electric Company) :
Unbundled Rates Filing :
:
I/M/O of the Energy Master Plan : BPU Docket No. EO97070457
Phase II Proceeding to Investigate :
the Future Structure of the :
Electric Power Industry : STIPULATION
(Atlantic City Electric Company) : OF
Restructuring Filing : SETTLEMENT
:
- ------------------------------------:
INTRODUCTION
On April 30, 1997, the New Jersey Board of Public Utilities
("BPU" or the "Board") issued a report entitled Restructuring the Electric Power
Industry in New Jersey: Findings and Recommendations, Docket No. EX94120585Y,
April 30, 1997 (hereinafter "Final Report"). The Board also directed the State's
electric utilities to make comprehensive filings addressing three areas: rate
unbundling, stranded costs, and industry restructuring. Atlantic City Electric
Company ("Atlantic" or the "Company") submitted its filing on July 15, 1997. The
Board retained the restructuring portion of the filing, but transmitted the rate
unbundling and stranded costs aspects of the filing to the Office of
Administrative Law for hearings.
<PAGE> 2
The Hon. William Gural, Administrative Law Judge ("ALJ"),
heard the rate unbundling and stranded costs matters over the course of nine
days of evidentiary hearings held on February 17, 1998 through February 20,
1998, and February 23, 1998 through February 27, 1998. During these hearings
Atlantic presented the following witnesses: Thomas Shaw, Dr. Philip O'Connor,
Henry Levari, Wayne Camp, William Gibson, Patricia MacFarland Goelz, Louis
Walters, Dr. Charles Moyer, Murray Stoltz, Carl Setterman and Paul Normand.
Numerous other witnesses were also presented by the various parties to the
proceedings. ALJ Gural rendered his Initial Decision in the rate unbundling and
stranded costs matters on August 17, 1998.
In an Order dated January 28, 1998, the Board identified eight
generic restructuring issues and decided to hold one set of restructuring
hearings for all parties. Following extensive discovery, 19 days of evidentiary
hearings were held before Commissioner Armenti beginning April 27, 1998 and
concluding May 28, 1998. Atlantic presented the following witnesses: Joseph
Bartolone, Tsion Messick, Thomas Shaw, Henry Levari, Eileen Unger, Ashley Brown,
and Rodney Frame.
On February 9, 1999, the New Jersey Electric Discount and
Energy Competition Act ( the "Act"), N.J.S.A. 48:3-49 et seq., was enacted. The
Act provides that retail electric customers shall have the opportunity to select
their electric suppliers on, or about, August 1, 1999. The Act also provides for
reduced retail electric rates.
The Board has encouraged the parties to attempt to negotiate a
settlement of these proceedings. As a result, the Company commenced detailed
settlement discussions with the parties on April 23, 1999. As a result of these
negotiations and settlement discussions, it is hereby agreed
<PAGE> 3
among the undersigned parties that this Stipulation of Settlement
("Stipulation") accurately states the terms of such resolution with regard to
issues in Atlantic's stranded costs and rate unbundling proceedings, as well as
certain restructuring issues specific to Atlantic.
STIPULATION OF SETTLEMENT
It is hereby stipulated and agreed, as of this 9th day of June, 1999, by and
among Atlantic City Electric Company, Enron Capital and Trade Resources, PP&L
EnergyPlus Co. (successor in interest to Pennsylvania Power & Light Company,
d/b/a PP&L EnergyPlus, for purposes of this case), New Jersey Retail Merchants
Association and New Jersey Food Council, who have jointly intervened in these
proceedings as the New Jersey Commercial Users, and the Independent Energy
Producers of New Jersey (collectively the "Parties") that:
RATE REDUCTIONS, TRANSITION PERIOD & UNBUNDLED RATES
1. The Parties agree that electric rate reductions shall be implemented
as follows to comply with the provisions of Section 4(d) of the Act:
a. The Parties acknowledge that the Company's rates are already lower
by a total of 1.3%, as a result of specific actions taken by the BPU in
recognition of the pending restructuring proceedings. In January, 1998,
the Company lowered rates by 1.2%, representing the net amount of
savings due to the merger of its parent company with Delmarva Power &
Light Company and expenses due to post-retirement benefits other than
pensions. In its Order approving the merger, the Board specifically
recognized that such net savings would be included as part of any
restructuring-related rate reductions. In June, 1998, rates were
lowered an additional 0.1% as a result of the Board's decision to
remove base rate
<PAGE> 4
expense items from the Company's rates during the 1997 LEAC proceeding.
Again, such Board action was based upon pending restructuring-related
rate changes.
b. An additional reduction from current rates shall be provided by the
Company for service rendered on and after August 1, 1999. This
reduction will be achieved, in part, by offsetting $36 million of
current regulatory asset charges with projected DSM and LEAC credits,
as set forth in Schedule A, reducing charges for electric power to
market levels, and setting the Market Transition Charge ("MTC") in a
manner that yields a net 3.9% reduction. To the extent that LEAC
credits exceed the amount necessary to offset these charges, such
excess credits will be applied to offset the outstanding balances of
other regulatory assets.
c. Subsequent to August 1, 1999, the Company will implement additional
rate reductions to give effect to any and all net savings achieved by
virtue of the buyout or buydown of contracts with Non-Utility
Generators (hereinafter "NUGs"), and the securitization of stranded
costs and/or the securitization of the cost of NUG buyouts or buydowns.
Reductions due to NUG buyouts or buydowns shall be given effect through
a revision to the NNC (as described in paragraph 23), as approved by
the Board. Reductions due to securitization shall be given effect upon
the implementation of a securitization bond recovery charge in rates,
as approved by the Board. The Company will implement such reductions as
soon as practicable after BPU approval, and to that end will include a
request to set such charges in any request for approval of a buyout,
buydown or securitization.
<PAGE> 5
d. To the extent the rate reductions provided for in paragraphs 1(a),
(b), and (c) above, do not provide an aggregate 10% reduction from
April 30, 1997 Rates (hereinafter "10% Reduction") for all customers,
the Company will implement a rate credit for service rendered on and
after August 1, 2002 through July 31, 2003 which, together with the
rate reductions provided for in paragraphs 1(a), 1(b) and 1(c), results
in the 10% Reduction. The rate credit implemented pursuant to this
paragraph will be sustained until July 31, 2003.
e. The Parties acknowledge that in order to fund and sustain the rate
reductions and the rate credit set forth in paragraphs 1(a) through
1(d) above, it may be necessary for the Company to defer the recovery
of revenues associated with basic generation service ("BGS"), NUG
costs, or other costs. No portion of the costs for BGS shall be
deferred prior to the deferral of any other deferrable cost, as more
specifically set forth in paragraph 27. Such deferral and recovery is
set forth more fully below in paragraph 27 through paragraph 29.
2. The Parties acknowledge that the Company's agreement to the
foregoing rate reductions and rate credit is based on the Board's approval of
the divestiture of certain of the Company's generating assets, as described more
fully below, and securitization of 100% of the net stranded costs associated
with those assets.
3. The four-year period commencing August 1, 1999, and terminating July
31, 2003, shall be hereinafter referred to as the "Transition Period."
4. The unbundled rates to be effective August 1, 1999, for each rate
class in Atlantic's Tariff for Electric Service have been developed using the
Company's 1996 Cost of Service Study.
<PAGE> 6
See Appendix A (rates/tariffs). The Parties acknowledge that the Company's
transmission rates are subject to revision by the Federal Energy Regulatory
Commission ("FERC"), and may increase or decrease. Accordingly, the transmission
and distribution rates are subject to revision, after the final determination of
FERC is rendered, in order to produce the same revenues as the rates set forth
in Appendix A.
BASIC GENERATION SERVICE AND SHOPPING CREDIT
5. The Parties have agreed to the following provisions with respect to
the "shopping credit", in accordance with Section 4(b) of the Act.
a. For the four years of the Transition Period, up to and including
July 31, 2003, the average "shopping credit" shall be the greater of
the amounts determined in accordance with paragraph 6, inclusive of BGS
rates and transmission rates, or the amounts set forth below:
<TABLE>
<CAPTION>
RATE CLASS 1999 2000 2001 2002 2003
---- ---- ---- ---- ----
Annual Annual Annual Annual Annual
------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C>
RS 5.15 5.20 5.20 5.25 5.30
RS-TOU 5.10 5.15 5.20 5.25 5.30
On Peak 6.59 6.65 - - -
Off Peak 4.67 4.72 - - -
MGS Secondary 5.45 5.50 5.60 5.70 5.80
MGS Primary 5.28 5.33 5.43 5.53 5.63
AGS Secondary 5.40 5.45 5.55 5.65 5.75
AGS Primary 5.17 5.22 5.27 5.32 5.37
AGS TOU Secondary 5.15 5.20 5.25 5.30 5.35
On Peak 6.11 6.17 6.23 6.29 6.35
Off Peak 4.25 4.29 4.33 4.38 4.42
</TABLE>
<PAGE> 7
<TABLE>
<S> <C> <C> <C> <C> <C>
AGS TOU Primary 5.05 5.10 5.10 5.10 5.10
On Peak 5.98 6.04 6.04 6.04 6.04
Off Peak 4.18 4.22 4.22 4.22 4.22
AGS TOU 4.30 4.30 4.30 4.30 4.30
Sub-Transmission
On Peak 5.08 5.08 5.08 5.08 5.08
Off Peak 3.57 3.57 3.57 3.57 3.57
AGS-TOU 4.25 4.25 4.25 4.25 4.25
Transmission
On Peak 5.00 5.00 5.00 5.00 5.00
Off Peak 3.54 3.54 3.54 3.54 3.54
TGS 4.30 4.30 4.30 4.30 4.30
SPL/CSL 2.97 3.05 3.07 3.10 3.12
DDC 3.58 3.68 3.71 3.75 3.78
SYSTEM AVERAGE 5.09 5.14 5.17 5.23 5.28
Shopping Credits include the following: Basic Generation Service Supply, Transmission, Ancillary
Services, Administrative Costs and Taxes
</TABLE>
The shopping credits set forth above are rate schedule averages. The
actual BGS rates to be charged to customers, and the corresponding
shopping credits resulting from those rates, will differ by blocks and
load factors for those customers with rates which contain demand and
energy components.
b. The shopping credits set forth in paragraph 5(a) include a
transmission rate component based on the average rate for transmission
for each rate class; the actual shopping credit for each customer will
be determined based on each customer's actual billing determinants and
the transmission rates in the Company's unbundled retail tariff.
c. In calculating the BGS rates pursuant to paragraph 6 below,
the BGS rates shall be set so that the resulting BGS rate for each rate
class remains in proportion to the system
<PAGE> 8
average BGS rate, as the BGS rates set forth in Appendix A have with
respect to the system average BGS rate for the BGS rates in Appendix A.
d. The Parties acknowledge that the Company's agreement to the
minimum shopping credits set forth in paragraph 5(a) is conditioned
upon the Board's approval of this Stipulation in its entirety, and in
particular is expressly conditioned upon the Board's approval of the
specific rate reduction provisions contained in paragraph 1.
6. The Parties agree that Atlantic shall provide BGS, in the
following manner:
a. The BGS rates shall be inclusive of the costs provided for
in section 9(a) of the Act, inclusive of losses and taxes.
b. Customers who choose to purchase electricity from electric
power suppliers ("EPSs") will not pay the BGS rates, and in addition
will not be billed for transmission charges by Atlantic (if such
charges are included in their charges from the EPS), which will be
based on each customer's billing determinants and the transmission
rates in the Company's unbundled retail tariff. See paragraph 4.
c. The sum of the BGS and transmission charges shall be the
"shopping credit", subject to the provisions of paragraphs 5 and 6(b).
If the "shopping credit" for any rate class is the amount set forth in
the chart in paragraph 5(a), then the average BGS rate for the class
shall be set as the "shopping credit" less the transmission charge. To
the extent the rate for BGS as calculated in the first sentence of this
paragraph, added to the average rate for transmission, produces a
shopping credit in excess of the shopping credit levels in the chart in
paragraph 5(a), then such BGS rate and the resulting shopping credit
shall be utilized. The
<PAGE> 9
Parties agree that the shopping credit mechanism set forth in
paragraphs 5 and 6 satisfies the requirements of Section 4(b) of the
Act.
d. The rates as determined pursuant to paragraph 6(a) may be
limited to the extent any portion of such BGS costs need to be deferred
pursuant to paragraph 1(e) above. The shopping credit calculated from
the BGS rate would similarly be limited.
e. The Parties further recognize and agree that additional
shopping-related savings, resulting from customers receiving electric
generation service from an EPS at a price less than the shopping
credit, are above and beyond the rate reductions set forth in paragraph
1 of this Stipulation.
7. The Parties agree that Atlantic shall procure power for BGS through
an open, competitive bidding process. During the first three years of the
Transition Period, up to and including July 31, 2002, Atlantic plans to solicit
proposals (the "RFP Process") for the provision of wholesale supply for BGS in
twelve month pricing cycles, or such other cycles as Atlantic deems necessary or
prudent. Atlantic will submit its plans for the RFP Process to the BPU by
September 15, 1999. Atlantic intends to commence the RFP Process as soon as
practicable after such date and approval of the Plan by the BPU, with the goal
of concluding such process and entering into a contract for BGS supply by
December 15, 1999. Any agreements for the provision of BGS shall be presented
to, and subject to the approval of, the BPU. The Parties further agree that to
the extent the Company has supply resources available from its NUG sources, the
Company will apply such resources toward the BGS supply requirements and conduct
the bidding process for the net BGS supply requirements resulting therefrom.
<PAGE> 10
8. In recognition of Atlantic's large seasonal customer base, which
results in increased costs for energy and capacity to serve customers from June
through September, the Parties agree that customers switching into BGS from an
EPS shall be required to remain on BGS for a minimum 12 month period; however,
any customer, while switching service from one EPS to another, in accordance
with Board-authorized switch rules, may return to BGS for thirty (30) days
without being required to remain on BGS; provided, however, that this exception
shall not be available to any customer who returned to BGS and then switched to
an EPS within the previous twelve (12) months. However, any residential customer
who returns to BGS due to the refusal or the inability of the customer's EPS to
continue to provide service to that customer shall not be required to remain on
BGS for a minimum 12 month period. The Company will have the option of
reviewing, with the Parties, the BPU and Staff, the residential seasonal BGS
customer base to determine whether a filing for approval of a separate
residential billing tariff, to avoid subsidies within the residential class
between seasonal and year-round customers, is necessary for the summer season in
2000 and beyond.
9. The Parties support the fact that in order to establish BGS
commencing August 1, 1999, until supply arrangements are made in accordance with
paragraph 7, Atlantic may have to secure supply through the Pennsylvania - New
Jersey - Maryland Interconnection ("PJM") for BGS, and that for purposes
thereof, the BGS pricing shall be based upon the capacity prices and the
applicable locational marginal prices of energy as reported by the
Pennsylvania-New Jersey-Maryland Office of Interconnection ("PJM OI"). Such
capacity and energy prices shall also be used as the market value of the NUG
resources which may be employed for BGS, with all NUG costs above that recovered
pursuant to paragraph 23.
<PAGE> 11
10. The Parties agree that the Company may at its option utilize its
affiliated service company to make arrangements for the BGS supply pursuant to
paragraphs seven through fourteen, and that such arrangements shall be conducted
on behalf of the Company as a regulated service. Neither the Company nor the
affiliated service company shall provide information relevant to the provision
of BGS and the bidding process to any competitive affiliate of the Company,
either directly or indirectly through the medium of another affiliate of the
Company, unless that information is provided contemporaneously to all others
bidding to provide BGS to Atlantic. The Company and the affiliated service
company shall receive and maintain all BGS bids, and discussions related
thereto, in a confidential manner, and not disclose such information, unless
said information is otherwise made public pursuant to law, regulatory act, or
agreement with the provider of the information. Employees of the affiliated
service company who transfer to any competitive affiliate of the Company shall
be kept separate from, and shall not participate in, any proposal by the
competitive affiliate to provide BGS to Atlantic.
11. The Parties agree that the Company may, at its option, use energy
and capacity obtained through one or more "parting contracts," as described in
paragraph 20 below, for the provision of BGS. The Parties further agree that the
Company may utilize certain financial instruments to decrease ratepayer exposure
to price spikes and price volatility, for example, hedging. It is recognized by
the Parties that the use of some of these products could result in costs which
exceed the spot market. The Parties agree that the cost of such parting
contracts and financial instruments, as well as all other reasonably and
prudently incurred costs associated with the procurement and provision of BGS,
shall be recoverable in rates for BGS pursuant to Section 9(e) of the Act.
<PAGE> 12
12. The Parties acknowledge that pursuant to Section 9(a) of the Act
the Company has a minimum obligation to provide BGS through July 31, 2002 to
those retail customers who choose to remain with the utility. The responsibility
for BGS for the fourth year of the Transition Period, after July 31, 2002, shall
be bid out during the third year of the Transition Period. Bidders shall bid for
the right to provide BGS during the year commencing August 1, 2002. The bids
shall be based on the minimum shopping credits for the applicable time periods,
as set forth in paragraph 5(a). Depending on the bidders' perceived value at the
time of the right to provide BGS, the bids shall provide for either: (i) a
payment from the bidder to the Company, to provide BGS at a price based on the
minimum shopping credit, as described in paragraph 6; (ii) the provision of BGS
at a rate which results in shopping credits for the applicable time period, as
set forth in paragraph 6; or (iii) a payment from the Company to the bidder, if
the BGS rate proposed by the winning bidder is such that some portion of the BGS
revenues must be deferred, in accordance with paragraph 1(e), such payment to be
equal to the portion of the BGS rate which can not be charged to the customers,
but which must be deferred. If the winning bid results in a net payment to the
Company, such payment shall be applied to reduce the balance of the Deferred
Revenues pursuant to paragraph 27, or any other under-recovered balance. If the
winning bid for BGS results in a net payment by the Company, such payment shall
be subject to deferral and subsequent recovery, as part of the Deferred Revenues
as set forth in paragraphs 27-29. At the conclusion of the Transition Period,
BGS will no longer be offered by the Company. The Parties hereto further agree
that the Board should establish a structure and procedures for the provision of
BGS after the Transition Period.
13. The Parties agree that a competitive affiliate of the Company may
be permitted to bid to provide wholesale supply for BGS service, and bid to
provide BGS pursuant to paragraph 12,
<PAGE> 13
during the Transition Period, subject to the affiliate relations standards to be
adopted by the Board. If a competitive affiliate of the Company participates in
any such bid, the Company and its affiliated service company shall utilize the
services of an independent consultant to review the bids, pursuant to criteria
to be set in developing the RFP process, and present the results to the Company
so as to not reveal which bid is from a competitive affiliate.
14. The Parties agree that the bidding procedures to be conducted for
the BGS supply during the Transition Period as described above shall be
conducted on behalf of the regulated utility, and that all competitive
information relating to bids which may be tendered shall be treated as
proprietary and confidential, and shall not be made available to a competitive
affiliate of the Company.
15. The Company agrees that it will not promote BGS as a competitive
alternative.
STRANDED COSTS
16. The Company shall be permitted to recover 100% of its net stranded
costs, including 100% of the stranded costs associated with the Company's
non-utility generator power contracts.
17. The Company has agreed, subject to the terms of this settlement, to
divest its interests in the B.L. England, Keystone, Conemaugh, Peach Bottom,
Salem and Hope Creek generating stations. The net divestiture proceeds will be
used to determine the Company's generation related stranded costs. Generation
related stranded costs shall mean the excess of net book value as of the closing
date(s) of the sale(s) over net divestiture proceeds. Net divestiture proceeds
are defined as the excess of the selling price(s) of the generating assets over
the transaction costs incurred by the Company. The transaction costs shall be
reasonable, verifiable and necessary, and shall include (but not necessarily be
limited to) sales and transfer taxes, state, federal and local taxes,
consultants fees,
<PAGE> 14
broker commissions, legal fees, investment banking fees, title transfer fees,
real estate transfer and related costs, mortgage and financing costs, real
estate taxes, transportation and system-separation costs (including outside
contractor, engineering, purchased materials and labor costs) associated with
the divestiture activities, paid overtime and out-of-pocket expenses for Company
employees associated with the divestiture activities, and any arrangements to
address direct and indirect employee impacts from the divestiture including
retirement, severance and any other employee-related benefit costs.
18. Final determination of the net divestiture proceeds shall be
undertaken only upon the completion of the transfer of all of the generation
assets listed in paragraph 17 to each purchaser thereof, as set forth herein.
a. Such final determination shall be made within a separate divestiture
proceeding, to be filed by Atlantic pursuant to standards to be set by
the Board, subject to the terms of this Stipulation as approved by the
Board in its final decision or Order herein. The final determination of
the net divestiture proceeds shall constitute only a true-up of actual
selling price(s), book value(s) and transaction costs, and not a
further review on the merits of the transaction.
b. Subject to the true-up proceeding referenced in paragraph 18(a), the
Board Order approving this Stipulation shall constitute a Board
determination that the transfer of the Company's generation and related
assets to third parties, in accordance with the standards to be adopted
pursuant to paragraph 19, as described in the Company's future
divestiture filings, will be approved by the Board in the future
divestiture dockets without condition, addition or modification, at the
agreed upon selling price(s), which shall be considered the "full
<PAGE> 15
market value" of the assets being transferred for the purposes of
Section 11(c)(1) of the Act, and on the terms, specified in the future
divestiture petitions. The Parties acknowledge that such transfers
require various regulatory approvals or waivers, including, without
limitation, the Board, the Federal Energy Regulatory Commission
("FERC"), the Nuclear Regulatory Commission and other agencies.
Provided the Company files a proposal for divestiture in accordance
with the standards to be set as referenced in paragraph 19, the Parties
will neither oppose, nor support any opposition to, any proceeding
seeking the approval of such sales or the terms thereof, or seeking any
other order or approval as may be required in order to consummate such
sales, before the Board or any other adjudicatory or regulatory body,
nor will the Parties seek to intervene in any such proceeding without
the consent of the Company, except as to matters not addressed in this
Stipulation.
c. With respect to the proceedings referenced in paragraph 18(b), the
IEPNJ and its current members state that, while they support the
concept of the divestiture of assets as set forth in paragraph 17, they
reserve the right to move before the BPU to seek the review of any
specific transfer of any generation asset listed in paragraph 17.
d. Any party who participates as a bidder in any sale conducted as part
of such divestiture shall have the same rights as any other bidders in
any BPU proceeding concerning such sale.
e. Nothing herein shall prevent a party from intervening in any such
proceeding solely for monitoring purposes.
19. In order to effectuate a timely divestiture of the Company's
generation assets, the Parties recognize that the Board must take certain steps.
Therefore, within thirty (30) days of a
<PAGE> 16
submission by the Company, the Board will finalize divestiture standards
applicable to Atlantic's generating assets. Nothing contained in this
Stipulation shall foreclose any Party from participating fully before the BPU in
formulating divestiture standards.
20. The Parties agree that the use of "parting contracts" entered into
by the Company with purchasers of its generation assets, as part of the sale of
such assets to those purchasers, to the extent they make possible or enhance the
sale of such assets, and are approved by the Board, are in the public interest,
and in accordance with applicable law. The Parties agree that the term of any
"parting contract" will not exceed four (4) years. Further, the Parties agree
the rates and costs contained therein are an integral aspect of the sale of the
generating assets. Therefore, the Company may flow-through, and fully and timely
recover, the rates specified in the "parting contracts," and the resulting
costs, from its customers. Should the "parting contract" rates and/or costs be
at levels which are above market cost, then the Company will fully and timely
recover such costs through a mechanism similar to the NNC described in paragraph
23.
21. The Company agrees to forego recovery of $9 million in net stranded
costs associated with its Deepwater Station and its Combustion Turbines, as set
forth in Schedule B ("Transferred Units"), and as set forth herein.
a. Pursuant to Section 7(d) of the Act, the Parties will not object to
the Board approving the transfer of the Transferred Units to an
unregulated affiliate of the Company. The Parties agree that the
transfer value of the Transferred Units shall be the net book value of
the assets at the time of the transfer, adjusted for the application of
Financial Accounting Standards Board ("FASB") Statement No. 121
("Adjusted Book Value"). Such transfer prices will, and are intended
to, ensure that the Company receives full and fair compensation for the
<PAGE> 17
Transferred Units and that Atlantic will not retain any liabilities
associated with the Transferred Units. The Company shall not bear any
expenses of the Transferred Units after the transfer to an unregulated
affiliate. The Company shall have auditable accounting protocols in
place no later than the effective date of the transfer to assure that
all expenses and capital expenditures related to the Transferred Units
will not be borne by the Company. If, within three (3) years of the
date of this Stipulation, any Transferred Unit is sold to a
non-affiliate of Atlantic, the net after-tax gain over the Adjusted
Book Value shall be shared equally between the Company and the
customers, in a manner to be determined by the Board.
b. It is the position of Enron that if the transfer outlined
in paragraph 21(a) takes place, the Transferred Units should be
maintained as a capacity resource within the PJM system for the
Transition Period.
c. With respect to affiliate issues, the parties, with the
exception of Enron and IEPNJ, recognize that the Board has released
draft affiliate relationship standards for comment, and will be
adopting affiliate relationship standards pursuant to the Act prior to
the completion of the transfer of the Transferred Units to any
affiliate, and that such standards will be applied to the relationship
between Atlantic and its affiliates. Enron and IEPNJ contend that the
Affiliate Standard of Conduct that should apply is as follows:
"The competitive generation affiliate shall not offer power or
other services to any of its affiliates which are not made
generally available to non-affiliated companies, nor shall it
offer such power or other services to affiliates at prices
more favorable than those generally
<PAGE> 18
available in the competitive marketplace and/or to those
offered to non-affiliated companies."
22. The Parties agree that there shall be no amortization of stranded
costs associated with generating assets during the period between August 1, 1999
and the divestiture of the generating assets. Once divestiture has been
completed, and the actual stranded costs thereof have been determined,
amortization of such stranded costs shall commence.
23. The Parties acknowledge that the Company is entitled to full and
timely recovery of 100% of the costs associated with its NUG purchased power
contracts. The Parties recognize that each of these non-utility generator
contracts have been previously reviewed and approved for full and timely
recovery by the Board. Therefore, consistent with Section 13(a)(3) of the Act
and other applicable law, the Parties agree that the Company shall be permitted
to fully recover, dollar-for-dollar, the costs associated with its NUG
contracts, over the life of each such contract. The Parties agree that the
Company shall utilize a Net Non-Utility Generator Charge ("NNC") as a component
of the MTC to recover the stranded costs associated with the purchase of power
from NUGs. The NNC shall be equal to the difference between the cost of the
NUG-contract purchased power and either (a) the proceeds realized by the Company
from the sale of that NUG-contract power in the competitive wholesale market,
(b) the pricing set forth in paragraph 7, to the extent NUG resources are
utilized as set forth in paragraph 7, or (c) the pricing set forth in paragraph
9, to the extent NUG resources are utilized as set forth in paragraph 9. Such
proceeds will be adjusted to reflect a deduction for the reasonable marketing
and administrative costs associated with the sale of the NUG-contract power into
the wholesale market. The NNC shall also include swap breakage costs incurred in
connection with a previous amendment to one of its NUG contracts, which costs
have been
<PAGE> 19
recovered to date through the Energy Adjustment (EA) clause charge. The NNC
shall continue over the actual term of each of the Company's NUG contracts, and
shall be applied as a non-bypassable wires charge to retail customers. In the
event, of a NUG-contract buyout, buydown or restructuring, the Company will be
provided with an incentive for restructuring amounting to ten (10) percent of
the net savings, except for the Pedricktown Project for which the incentive will
be five (5) percent, and the NNC shall be adjusted accordingly. As set forth
below, the Parties agree to 100% securitization, over the remaining contract
term, of the costs associated with any buyout, buydown or restructuring of the
Company's NUG power contracts. In the event of such buyout, buydown, or
restructuring, and prior to the securitization of the costs for same, the
Company shall include such costs in its MTC recovery.
24. The Parties agree that the Company will incur additional stranded
costs for restructuring-related items that are capital in nature, the estimated
costs of which are set forth in Schedule C. Therefore, the Parties agree that
the Company may recover these costs through securitization of up to 75% of total
capital expenses for terms up to 15 years. Capitalized costs not recovered
through securitization will be recovered, with a full rate of return on the
unamortized balance, over a period of up to 8 years through a component of the
Market Transition Charge ("MTC").
25. The Parties agree that net stranded costs for restructuring related
items of an operating nature, other than consumer education costs, shall be
recoverable on a full and timely basis through a component of the MTC. A listing
of these costs, and the estimates thereof, are attached as Schedule D.
<PAGE> 20
26. This Stipulation constitutes a balancing of the interests of the
various Parties, and the Company's agreements as to rate reductions and stranded
cost recovery reflect such balance. A determination by the Board contrary to
this agreement of the Parties, as to the treatment of the Company's future
divestiture petition(s) and the quantification of stranded costs as a result
thereof, would upset such balance. Thus, if the Company would be required to
write off certain amounts as a result of the Board orders issued in the future
divestiture dockets, or otherwise required in the divestiture dockets to absorb
stranded costs with respect to the assets being divested in excess of the
amounts contemplated in this Stipulation, this Stipulation, and the Board Order
issued in respect hereof, shall be deemed modified to the extent necessary to
permit the Company to recover such amounts that would otherwise be required to
be written off, or such excess stranded costs, through the MTC.
DEFERRALS AND RECOVERY OF DEFERRALS
27. As described in paragraph 1(e) above, the Parties recognize that
the Company may have to defer recovery of some portion of its revenues in order
to achieve and/or sustain rate reductions or the rate credit through the end of
the Transition Period. The revenues which may be so deferred (the "Deferred
Revenues") are those incurred during the Transition Period to meet the costs of
BGS (as set pursuant to paragraph 6), the NNC (as set pursuant to paragraph 23),
and the costs recoverable through the MTC (set forth in paragraph 25).
Therefore, during the Transition Period, the Company will utilize a deferred
accounting mechanism to provide for full recovery of any Deferred Revenues.
Revenues for BGS will only be deferred to the extent necessary to fund and
sustain the rate reductions and the rate credit set forth in paragraphs 1(a)
through 1(d), and then only after the deferral of any other item of Deferred
Revenues, as set forth in this paragraph. Any Deferred Revenues, together with a
full rate of return on the unrecovered balance, will be recovered by the Company
no later than August 1, 2007. The Parties agree that the Company has an absolute
right to recover the Deferred Revenues, along with the Company's authorized rate
of return, from the Company's ratepayers in a full and timely manner. The
Parties acknowledge that this deferral and recovery schedule represent a
balancing of the Company's financial requirements and a desire to mitigate the
rate impact on customers. Therefore, the Board Order approving this Stipulation
shall constitute final approval of the recovery of the Deferred Revenues, which
is an integral part of this Stipulation. Further, the Parties agree that any
repayment of the Deferred Revenues by ratepayers will not be included within
operating income in any ratemaking proceeding, and it will not be considered
when determining the Company's authorized rate of return in future ratemaking
proceedings. Moreover, the Parties will neither oppose, nor support any
opposition to, any proceeding relating to the recovery of the balance of
Deferred Revenues. The Parties hereto
<PAGE> 21
specifically reserve the right to intervene in any such proceeding in order to
support such full and timely recovery.
28. The balance of the Deferred Revenues shall be recovered after the
Transition Period through a charge to be included in post-Transition Period
regulated rates, which shall generate a post-Transition Period regulated cash
flow stream for that purpose, and the balance of the Deferred Revenues shall
thereupon be reversed from the Company's balance sheet as it is recovered. This
assurance of recovery, which the Board's Order approving this Stipulation will
provide, is intended in all respects to comport with and satisfy the standards
of the FASB, including those FASB standards under which the Company is permitted
to maintain the Deferred Revenues as a regulatory asset rather than being
required to record the balance as a current expense.
29. In recognition of the requirement in Section 13(h) of the Act that
rate reductions not impair an electric public utility's financial integrity such
that access to the capital markets for the continued provision of safe, adequate
and proper utility service is impaired, in the event, at any point in the
Transition Period, either (a) the balance of the Deferred Revenues exceeds $50
million, or (b) the Company's senior secured debt is downgraded or the Company
is placed by a rating agency on credit watch, the Company may petition the Board
for appropriate relief. The Parties agree that, in their view, under the Act the
Board would have the discretion and authority, in response to such a petition,
to, among other things, take ratemaking action to preserve the Company's
financial integrity. Nothing herein shall be deemed to limit the Company's right
otherwise to petition the Board for any relief deemed necessary by the Company
at any time.
<PAGE> 22
SECURITIZATION
30. The Parties agree that the Company shall be permitted to securitize
100% of the net stranded costs associated with its divested generation assets.
This figure shall be calculated in accordance with paragraph 17 above. The term
of such securitization financing associated with the divested generation assets
shall not exceed 15 years. The Parties further agree that taxes related to
securitization, reflecting the grossed-up revenue requirement number associated
with the level of stranded costs as determined in paragraph 17 above, are
legitimate recoverable stranded costs, and are to be recovered through a
separate component of the MTC with a term identical to the term of the
securitization financing. The Parties further agree that the Company is entitled
to the full and timely recovery of all transition bond charges ("TBC"), along
with applicable taxes.
31. The Parties agree that the Company shall be permitted to securitize
100% of the net stranded costs associated with the restructuring, buyout or
buydown of it NUG power contracts. The term(s) of the related securitization
financing shall be no longer than the remaining terms of the respective NUG
contracts which have been restructured or terminated. The Parties further agree
that the Company is entitled to the full recovery of all transition bond
charges, along with applicable taxes.
32. The Parties agree that the Company shall be permitted to securitize
75% of all restructuring-related net stranded costs that are capital in nature,
as set forth in paragraph 24. The term of the related securitization shall not
exceed 15 years.
33. It is expected that third parties may be authorized to provide
billing and collection services in the future as a result of the statutorily
required billing and metering proceeding. Even if third party billing and
collection has not been so authorized by the time the Company seeks to effect a
securitization transaction, the Parties recognize and agree that appropriate
creditworthiness
<PAGE> 23
standards applicable to any third parties that may ultimately provide billing
and collection services would have to be in place by the time of any
securitization transaction in order to satisfy credit rating agencies and the
financial community so that securitization may proceed. Therefore, the Board
Order approving this Stipulation shall constitute a Board determination that, if
such creditworthiness standards are not in place before the Company undertakes
securitization of any of its assets, such standards will be incorporated in the
applicable bondable stranded costs rate order.
SOCIETAL BENEFITS CHARGE
34. The Parties agree that consistent with Section 12 of the Act, the
Company will establish a Societal Benefits Charge ("SBC"). The SBC will include
costs related to: (1) social programs, (2) nuclear plant decommissioning costs,
(3) Demand Side Management ("DSM") programs, and (4) consumer education.
35. The SBC will be set at the level of costs for the above items
already in rates as of the date of this Stipulation. During the Transition
Period, the funding of SBC initiatives may vary from the level of funding
currently in rates. The Parties reserve the right to assert their respective
positions in proceedings related to the Comprehensive Resource Analysis to be
performed by the Company. An annual true-up process will be established to
provide for the full and timely recovery of SBCs. To the extent that full and
timely recovery of the SBC costs prevents the Company from achieving the rate
reductions described in paragraphs 1(b) and 1(d) above, the Company agrees to
defer a portion of the SBC cost recovery subject to the same terms and
conditions as described in paragraph 27.
<PAGE> 24
OTHER ISSUES
36. All tax expenses shall be determined on a utility stand-alone
basis, and not by imputing the tax effects of a consolidated return. The Company
is entitled to full and timely recovery of all taxes in connection with
restructuring and with the divestiture of the Company's generating assets.
37. The Company shall be authorized to continue to provide service
under its existing Off-Tariff Rate Agreements ("OTRAs"). The Company agrees not
to transfer any OTRA to an unregulated affiliate, on the condition that the
Company may utilize the services of an affiliated energy trading segment to
procure the supply to serve under the OTRA. In addition, the Company agrees that
any OTRA customer may choose to end its contract, shop for and receive
generation from an EPS or go on BGS, and be provided unbundled service under the
Company's tariffs. The Company will provide notice of this provision to the OTRA
customers.
38. With regard to the presentation by the Company of a NUG contract
restructuring proposal, the Parties acknowledge the importance of the prompt
resolution of such proposal, in order that the benefits of such restructuring to
the Company and its customers may commence. Accordingly, the Board shall review
and render a decision within 45 days of the Company filing such restructuring
proposal with the Board.
39. The Board shall order that the existing regulatory asset associated
with the application of FASB Statement No. 109 to the transmission and
distribution assets of the Company shall be preserved and shall be addressed by
the Board in a future regulatory proceeding.
40. The Parties agree that experimental Residential Time-of-Use rates
shall be discontinued as of August 1, 2000. The Parties further agree that the
AGS Time-of-Use rates will
<PAGE> 25
be closed to any new customers on August 1, 1999, and the rate will continue
through the Transition Period, unless the number of customers taking service
under that rate schedule drops below 25. Customers currently being served under
these rate classes shall be provided with at least 90 days' notice of the
discontinuation, and shall be advised that service provided by EPSs may provide
electric power supply with time-differentiated pricing.
41. The Parties agree that the Interruptible Rider shall be
discontinued as of December 31, 1999. Customers currently being served under
this rate will be advised that service provided by EPSs may provide electric
power supply with interruptible pricing.
42. The Parties agree that the Standby and Large Standby Riders
contained in the present utility tariff shall reflect reductions and credits to
be made in accordance with this Stipulation and shall be modified to provide for
fixed, unbundled charges for transmission, distribution and customer services,
and shall be modified further to provide that standby power supply shall be
provided from time to time, as required by the customer, at the BGS rate.
43. The Parties agree that expenses to redeem and retire outstanding
capital in connection with the recovery of stranded costs shall be recognized as
stranded costs, and shall be included in the MTC.
44. In setting the annual level of charges for BGS during the
Transition Period, for any MTC that continues beyond the Transition Period, and
for the SBC, NNC and the TBC, the Company will utilize a methodology similar to
that currently used for setting its Energy Adjustment (EA) clause charges. The
BGS, SBC, NNC, MTC and TBC components will be set annually, based upon
projections of costs and of sales. Actual costs will be accounted for on a
deferred accounting basis, and when the BGS, SBC, NNC, MTC and TBC are set in
the following year, each of those
<PAGE> 26
rate components will be set to recover any underrecovery in the deferred
balance, as well as the projected costs for the upcoming year. The setting of
the BGS, SBC, NNC and MTC shall be subject to providing the rate reductions as
set forth in paragraph 1, and the Deferred Revenues provisions of paragraphs
27-29. Any overrecoveries in the deferred balances for the BGS, SBC, NNC or MTC
will be applied as a credit to the respective rate components in the same
manner. The same procedure will be followed for each year in which the BGS, SBC,
NNC, MTC and TBC charges are to be set.
45. With regard to actions within the Company's control, the Company
agrees it will make a good faith effort to handle electronic data interchange in
relation to the delivery of electricity from EPSs to retail customers by October
1, 1999.
BILLING AND METERING
46. The Parties agree to work cooperatively to conclude the statutorily
required billing and metering proceeding in an expedited fashion, which
proceeding the Parties request that the Board conclude by May 1, 2000.
NO WAIVER OF RIGHTS
47. Under the Act, statutory limitations are imposed on the regulated
rates that the Company may charge to customers. At the same time, the Company
remains statutorily obligated to procure capacity and energy for those customers
who receive BGS, at unpredictable and uncontrollable market prices. The Parties
acknowledge that the Company is concerned that these statutory limitations and
obligations may ultimately impair the Company's access to capital, may become
confiscatory as against the Company, or may otherwise prove to be
unconstitutional in application. The Parties hereby acknowledge that the Company
is not waiving its absolute right to assert that the
<PAGE> 27
effect of the legislation, or the Board Order approving this Stipulation, as
applied, is or may become confiscatory or otherwise unconstitutional, and to
seek any and all legal redress or remedy for the situation. Participation by the
Company in settlement negotiations and this Stipulation shall not be deemed a
waiver of those rights.
<PAGE> 28
CONCLUSION
The undersigned agree that this Stipulation contains mutually
balancing and interdependent provisions and is intended to be accepted and
approved in its entirety and the Parties agree to be bound by its terms. In the
event any particular aspect of this Stipulation is not accepted and approved by
the Board, or is modified by the Board, any party hereto may deem this
Stipulation to be null and void, and upon such declaration, the Parties shall be
placed in the same position that they were in immediately prior to the execution
of this Stipulation.
Atlantic City Electric Company New Jersey Retail Merchants Association
By:/s/ Stephen B. Genzer, Esquire By:/s/ Melanie Willoughby
- --------------------------------- -------------------------
LeBoeuf, Lamb, Greene &
Macrae, LLP
Attorneys for Atlantic City
Electric Company
New Jersey Commercial Users
Independent Energy Producers of New Jersey
By: /s/ William Harla By:/s/ James E. McGuire
- --------------------- -----------------------
Enron Capital and Trade Resources PP&L EnergyPlus, Co.
By: /s/ Murray E. Bevan By:/s/ Howard O. Thompson
- ----------------------- -------------------------
Morgan and Landis
Attorneys for PP&L
New Jersey Food Council EnergyPlus, Co.
By: /s/ James M.
- -----------------
<PAGE> 29
ATLANTIC CITY ELECTRIC APPENDIX A
STIPULATION OF SETTLEMENT
AUGUST 1, 1999 UNBUNDLED RATE SUMMARY
<TABLE>
<CAPTION>
TARIFF BLOCKS CUST BGS MTC NNC TRANS DISTR DSM DECOM
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
RS CUSTOMER $2.48
SUM 'First 750 KWh 0.045737 0.013504 0.019109 0.005934 0.036511 0.000455 0.000855
WIN' First 500 KWh 0.045737 0.013512 0.019109 0.005934 0.038503 0.000455 0.000855
SUM '> 750 KWh 0.045737 0.023897 0.019109 0.005934 0.041083 0.000580 0.000855
WIN > 500 KWh 0.045737 0.001891 0.019109 0.005934 0.029923 0.000286 0.000855
RS TOU CUSTOMER 3.62
DEMAND CHARGE
PERIOD 1 (SUMMER ON) - 5.41
PERIOD 2 (WINTER ON) - 1.82
ENERGY CHARGE
PERIOD 1 (SUMMER ON) 0.060136 0.200905 0.019109 0.005892 0.057520 0.000511 0.000855
PERIOD 2 (SUMMER OFF) 0.041015 0.049910 0.019109 0.005892 0.020074 0.000511 0.000855
PERIOD 3 (WINTER ON) 0.060136 0.160506 0.019109 0.005892 0.048626 0.000511 0.000855
PERIOD 4 (WINTER OFF) 0.041015 0.048321 0.019109 0.005892 0.019724 0.000511 0.000855
RS TOU-E CUSTOMER 3.62
ENERGY CHARGE
PERIOD 1 (SUMMER ON) 0.060136 0.009291 0.019109 0.005892 0.119057 0.000494 0.000855
PERIOD 2 (SUMMER OFF) 0.041015 0.000006 0.019109 0.005892 0.010881 0.000494 0.000855
PERIOD 3 (WINTER ON) 0.060136 0.009897 0.019109 0.005892 0.081936 0.000494 0.000855
PERIOD 4 (WINTER OFF) 0.041015 0.000002 0.019109 0.005892 0.007216 0.000494 0.000855
</TABLE>
<TABLE>
<CAPTION>
TARIFF BLOCKS LC-904 REG TOTAL
UNCOLL. ASSETS RATE
<S> <C> <C> <C> <C>
RS CUSTOMER 2.48
SUM 'First 750 KWh 0.001473 0.000384 0.123963
WIN' First 500 KWh 0.001473 0.000384 0.125963
SUM '> 750 KWh 0.001473 0.000384 0.139053
WIN > 500 KWh 0.001473 0.000384 0.105593
RS TOU CUSTOMER 3.62
DEMAND CHARGE
PERIOD 1 (SUMMER ON) 5.41
PERIOD 2 (WINTER ON) 1.82
ENERGY CHARGE
PERIOD 1 (SUMMER ON) - 0.000384 0.345311
PERIOD 2 (SUMMER OFF) - 0.000384 0.137750
PERIOD 3 (WINTER ON) - 0.000384 0.296019
PERIOD 4 (WINTER OFF) - 0.000384 0.135811
RS TOU-E CUSTOMER 3.62
ENERGY CHARGE
PERIOD 1 (SUMMER ON) - 0.000384 0.215217
PERIOD 2 (SUMMER OFF) - 0.000384 0.076636
PERIOD 3 (WINTER ON) - 0.000384 0.178701
PERIOD 4 (WINTER OFF) - 0.000384 0.074969
</TABLE>
Page 1 of 8
<PAGE> 30
ATLANTIC CITY ELECTRIC APPENDIX A
STIPULATION OF SETTLEMENT
AUGUST 1, 1998 UNBUNDLED RATE SUMMARY
<TABLE>
<CAPTION>
TARIFF BLOCKS CUST BGS MTC NNC TRANS
<S> <C> <C> <C> <C> <C> <C>
MGS-SECONDARY CUSTOMER - 1 PHASE 4.76
CUSTOMER - 3 PHASE 5.94
DEMAND CHARGE
SUM > 3 KW 2.46
WIN > 3 KW 2.02
REACTIVE DEMAND 0.06
ENERGY CHARGE
SUM < 300KWh 0.048583 0.056981 0.019109 -
WIN < 300 KWh 0.048583 0.057159 0.019109 -
SUM NEXT 900 KWH 0.048583 0.013645 0.019109 -
WIN NEXT 900 KWh 0.048583 0.000557 0.019109 -
SUM > 1200 KWh 0.048583 0.006214 0.019109 -
WIN > 1200 KWh 0.048583 0.000557 0.019109 -
CEILING LIMIT 0.048583 0.068677 0.019109 -
MGS-PRIMARY CUSTOMER - 1 PHASE 4.76
CUSTOMER - 3 PHASE 5.94
DEMAND CHARGE
SUM > 3 KW 4.35
WIN > 3 KW 3.56
REACTIVE DEMAND 0.05
ENERGY CHARGE
SUM < 300KWh 0.043008 0.070353 0.018546 -
WIN < 300 KWh 0.043008 0.070547 0.018546 -
SUM NEXT 900 KWH 0.043008 0.024288 0.018546 -
WIN NEXT 900 KWh 0.043008 0.002649 0.018546 -
SUM > 1200 KWh 0.043008 0.016387 0.018546 -
WIN > 1200 KWh 0.043008 0.010373 0.018546 -
CEILING LIMIT 0.043008 0.082839 0.018546 -
</TABLE>
<TABLE>
<CAPTION>
TARIFF BLOCKS DISTR DSM DECOM LC-904 REG TOTAL
UNCOLL. ASSETS RATE
<S> <C> <C> <C> <C> <C> <C> <C>
MGS-SECONDARY CUSTOMER - 1 PHASE 4.76
CUSTOMER - 3 PHASE 5.94
DEMAND CHARGE
SUM > 3 KW 4.23 6.69
WIN > 3 KW 3.46 5.48
REACTIVE DEMAND 0.32 0.37
ENERGY CHARGE
SUM < 300KWh 0.044974 0.000606 0.000855 (0.000179) 0.000384 0.171314
WIN < 300 KWh 0.045052 0.000606 0.000855 (0.000179) 0.000384 0.171569
SUM NEXT 900 KWH 0.027654 0.000606 0.000855 (0.000179) 0.000384 0.110657
WIN NEXT 900 KWh 0.022459 0.000606 0.000855 (0.000179) 0.000384 0.092374
SUM > 1200 KWh 0.024717 0.000606 0.000855 (0.000179) 0.000384 0.100289
WIN > 1200 KWh 0.022459 0.000606 0.000855 (0.000179) 0.000384 0.092374
CEILING LIMIT 0.050413 0.000700 0.000855 (0.000179) 0.000384 0.188542
MGS-PRIMARY CUSTOMER - 1 PHASE 4.76
CUSTOMER - 3 PHASE 5.94
DEMAND CHARGE
SUM > 3 KW 2.34 6.69
WIN > 3 KW 1.92 5.48
REACTIVE DEMAND 0.32 0.37
ENERGY CHARGE
SUM < 300KWh 0.035587 0.000422 0.000855 (0.000007) 0.000384 0.169149
WIN < 300 KWh 0.035643 0.000422 0.000855 (0.000007) 0.000384 0.169400
SUM NEXT 900 KWH 0.009245 0.000422 0.000855 (0.000007) 0.000384 0.096742
WIN NEXT 900 KWh 0.025964 0.000422 0.000855 (0.000007) 0.000384 0.091821
SUM > 1200 KWh 0.019979 0.000422 0.000855 (0.000007) 0.000384 0.099575
WIN > 1200 KWh 0.016240 0.000422 0.000855 (0.000007) 0.000384 0.089821
CEILING LIMIT 0.039858 0.000542 0.000855 (0.000007) 0.000384 0.186025
</TABLE>
Page 2 of 8
<PAGE> 31
ATLANTIC CITY ELECTRIC APPENDIX A
STIPULATION OF SETTLEMENT
AUGUST 1, 1999 UNBUNDLED RATE SUMMARY
<TABLE>
<CAPTION>
TARIFF BLOCKS CUST BGS MTC NNC TRANS DISTR DSM
<S> <C> <C> <C> <C> <C> <C> <C> <C>
AGS-SECONDARY
CUST 92.46
DEMAND CHARGE
Including 25 KW 1.13 5.43
26-900 KW 1.13 5.43
901-10000 KW 1.12 5.39
Excess Demand 1.11 5.30
Winter Demand 0.64 3.07
Reactive Demand 0.07 0.35
ENERGY CHARGE
First 82500 KWh 0.050681 0.005792 0.019109 - 0.004532 0.000638
> 82500 KWh 0.050681 0.004042 0.019109 - 0.004384 0.000638
> 330 KW demand 0.050681 0.004042 0.019109 - 0.004384 0.000638
AGS-PRIMARY
CUST 92.46
DEMAND CHARGE
Including 25 KW 1.74 4.81
26-900 KW 1.74 4.81
901-10000 KW 1.73 4.78
Excess Demand 1.70 4.71
Winter Demand 0.99 2.72
Reactive Demand 0.10 0.33
ENERGY CHARGE
First 82500 KWh 0.047292 0.009444 0.018546 - 0.005807 0.000404
> 82500 KWh 0.047292 0.007713 0.018546 - 0.005648 0.000404
> 330 KW demand 0.047292 0.007713 0.018546 - 0.005648 0.000404
</TABLE>
<TABLE>
<CAPTION>
TARIFF BLOCKS DECOM LC-904 REG TOTAL
UNCOLL. ASSETS RATE
<S> <C> <C> <C> <C>
AGS-SECONDARY
CUST 92.46
DEMAND CHARGE
Including 25 KW 6.56
26-900 KW 6.56
901-10000 KW 6.52
Excess Demand 6.41
Winter Demand 3.71
Reactive Demand 0.43
ENERGY CHARGE
First 82500 KWh 0.000855 (0.000244) 0.000384 0.081746
> 82500 KWh 0.000855 (0.000244) 0.000384 0.079849
> 330 KW demand 0.000855 (0.000244) 0.000384 0.079849
AGS-PRIMARY
CUST 92.46
DEMAND CHARGE
Including 25 KW 6.56
26-900 KW 6.56
901-10000 KW 6.52
Excess Demand 6.41
Winter Demand 3.71
Reactive Demand 0.43
ENERGY CHARGE
First 82500 KWh 0.000855 0.000047 0.000384 0.082779
> 82500 KWh 0.000855 0.000047 0.000384 0.080889
> 330 KW demand 0.000855 0.000047 0.000384 0.080889
</TABLE>
Page 3 of 8
<PAGE> 32
ATLANTIC CITY ELECTRIC APPENDIX A
STIPULATION OF SETTLEMENT
AUGUST 1, 1999 UNBUNDLED RATE SUMMARY
<TABLE>
<CAPTION>
TARIFF BLOCKS CUST BGS MTC NNC TRANS DISTR
AGT-SECONDARY
<S> <C> <C> <C> <C> <C> <C> <C>
CUST 268.65
DEMAND CHARGE
PERIOD 1 (SUMMER ON) 1.87 2.25
PERIOD 2 (SUMMER OFF) - 1.42
PERIOD 3 (WINTER ON) 1.42 1.71
PERIOD 4 (WINTER OFF) - 1.22
REACTIVE DEMAND 0.07 0.29
ENERGY CHARGE
PERIOD 1 (SUMMER ON) 0.058683 0.020928 0.019109 - 0.012737
PERIOD 2 (SUMMER OFF) 0.040135 0.000002 0.019109 - 0.005491
PERIOD 3 (WINTER ON) 0.058683 0.009161 0.019109 - 0.011764
PERIOD 4 (WINTER OFF) 0.040135 0.000012 0.019109 - 0.005099
AGT-PRIMARY
CUST 268.65
DEMAND CHARGE
PERIOD 1 (SUMMER ON) 1.94 2.18
PERIOD 2 (SUMMER OFF) - 1.42
PERIOD 3 (WINTER ON) 1.48 1.66
PERIOD 4 (WINTER OFF) - 1.22
REACTIVE DEMAND 0.08 0.28
ENERGY CHARGE
PERIOD 1 (SUMMER ON) 0.056936 0.010217 0.018546 - 0.021967
PERIOD 2 (SUMMER OFF) 0.038942 0.001775 0.018546 - 0.006007
PERIOD 3 (WINTER ON) 0.056936 0.008037 0.018546 - 0.015295
PERIOD 4 (WINTER OFF) 0.038942 0.000010 0.018546 - 0.008636
</TABLE>
<TABLE>
<CAPTION>
TARIFF BLOCKS DSM DECOM LC-904 REG TOTAL
UNCOLL. ASSETS RATE
AGT-SECONDARY
<S> <C> <C> <C> <C> <C> <C>
CUST 268.65
DEMAND CHARGE
PERIOD 1 (SUMMER ON) 4.12
PERIOD 2 (SUMMER OFF) 1.42
PERIOD 3 (WINTER ON) 3.14
PERIOD 4 (WINTER OFF) 1.22
REACTIVE DEMAND 0.36
ENERGY CHARGE
PERIOD 1 (SUMMER ON) 0.000475 0.000855 (0.000001) 0.000384 0.113169
PERIOD 2 (SUMMER OFF) 0.000475 0.000855 (0.000001) 0.000384 0.066450
PERIOD 3 (WINTER ON) 0.000475 0.000855 (0.000001) 0.000384 0.100430
PERIOD 4 (WINTER OFF) 0.000475 0.000855 (0.000001) 0.000384 0.066068
AGT-PRIMARY
CUST 268.65
DEMAND CHARGE
PERIOD 1 (SUMMER ON) 4.12
PERIOD 2 (SUMMER OFF) 1.42
PERIOD 3 (WINTER ON) 3.14
PERIOD 4 (WINTER OFF) 1.22
REACTIVE DEMAND 0.36
ENERGY CHARGE
PERIOD 1 (SUMMER ON) 0.000430 0.000855 - 0.000384 0.109335
PERIOD 2 (SUMMER OFF) 0.000430 0.000855 - 0.000384 0.066939
PERIOD 3 (WINTER ON) 0.000430 0.000855 - 0.000384 0.100483
PERIOD 4 (WINTER OFF) 0.000430 0.000855 - 0.000384 0.067803
</TABLE>
Page 4 of 8
<PAGE> 33
ATLANTIC CITY ELECTRIC APPENDIX A
STIPULATION OF SETTLEMENT
AUGUST 1, 1999 UNBUNDLED RATE SUMMARY
<TABLE>
<CAPTION>
TARIFF BLOCKS CUST BGS MTC NNC TRANS DISTR
AGT-SUBTRANSMISSION
<S> <C> <C> <C> <C> <C> <C> <C>
CUST 268.65
DEMAND CHARGE
PERIOD 1 (SUMMER ON) 1.99 2.13
PERIOD 2 (SUMMER OFF) - 1.42
PERIOD 3 (WINTER ON) 1.52 1.62
PERIOD 4 (WINTER OFF) - 1.22
REACTIVE DEMAND 0.10 0.26
ENERGY CHARGE
PERIOD 1 (SUMMER ON) 0.047660 0.042172 0.018200 - 0.006319
PERIOD 2 (SUMMER OFF) 0.032606 0.009079 0.018200 - 0.003898
PERIOD 3 (WINTER ON) 0.047660 0.027827 0.018200 - 0.005597
PERIOD 4 (WINTER OFF) 0.032606 0.008122 0.018200 - 0.003851
AGT-TRANSMISSION
CUST 268.65
DEMAND CHARGE
PERIOD 1 (SUMMER ON) 2.88 1.24
PERIOD 2 (SUMMER OFF) - 1.42
PERIOD 3 (WINTER ON) 2.19 0.94
PERIOD 4 (WINTER OFF) - 1.22
REACTIVE DEMAND 0.09 0.26
ENERGY CHARGE
PERIOD 1 (SUMMER ON) 0.046303 0.041904 0.018124 - 0.007689
PERIOD 2 (SUMMER OFF) 0.031679 0.009181 0.018124 - 0.004618
PERIOD 3 (WINTER ON) 0.046303 0.027792 0.018124 - 0.006773
PERIOD 4 (WINTER OFF) 0.031679 0.008220 0.018124 - 0.004559
</TABLE>
<TABLE>
<CAPTION>
TARIFF BLOCKS DSM DECOM LC-904 REG TOTAL
UNCOLL. ASSETS RATE
AGT-SUBTRANSMISSION
<S> <C> <C> <C> <C> <C> <C>
CUST 268.65
DEMAND CHARGE
PERIOD 1 (SUMMER ON) 4.12
PERIOD 2 (SUMMER OFF) 1.42
PERIOD 3 (WINTER ON) 3.14
PERIOD 4 (WINTER OFF) 1.22
REACTIVE DEMAND 0.36
ENERGY CHARGE
PERIOD 1 (SUMMER ON) 0.000376 0.000855 - 0.000384 0.115967
PERIOD 2 (SUMMER OFF) 0.000377 0.000855 - 0.000384 0.065399
PERIOD 3 (WINTER ON) 0.000376 0.000855 - 0.000384 0.100900
PERIOD 4 (WINTER OFF) 0.000377 0.000855 - 0.000384 0.064395
AGT-TRANSMISSION
CUST 268.65
DEMAND CHARGE
PERIOD 1 (SUMMER ON) 4.12
PERIOD 2 (SUMMER OFF) 1.42
PERIOD 3 (WINTER ON) 3.14
PERIOD 4 (WINTER OFF) 1.22
REACTIVE DEMAND 0.36
ENERGY CHARGE
PERIOD 1 (SUMMER ON) (0.000787) 0.000855 - 0.000384 0.114473
PERIOD 2 (SUMMER OFF) (0.000226) 0.000855 - 0.000384 0.064597
PERIOD 3 (WINTER ON) (0.000620) 0.000855 - 0.000384 0.099612
PERIOD 4 (WINTER OFF) (0.000215) 0.000855 - 0.000384 0.063606
</TABLE>
Page 5 of 8
<PAGE> 34
ATLANTIC CITY ELECTRIC APPENDIX A
STIPULATION OF SETTLEMENT
AUGUST 1, 1999 UNBUNDLED RATE SUMMARY
<TABLE>
<CAPTION>
TARIFF BLOCKS CUST BGS MTC NNC TRANS DISTR DSM
<S> <C> <C> <C> <C> <C> <C> <C> <C>
TGS
CUST 88.43
DEMAND CHARGE
Including 25 KW 2.50 2.99
26-900 KW 2.50 2.99
901-10000 KW 2.49 2.98
Excess Demand 2.45 2.93
Winter Demand 1.42 1.69
Reactive Demand 0.11 0.25
ENERGY CHARGE
First 82500 KWh 0.039889 0.016119 0.018124 - 0.006425 (0.001338)
> 82500 KWh 0.039889 0.014257 0.018124 - 0.006251 (0.001289)
> 330 KW demand 0.039889 0.012952 0.018124 - 0.006251 0.000016
</TABLE>
<TABLE>
<CAPTION>
TARIFF BLOCKS DECOM LC-904 REG TOTAL
UNCOLL. ASSETS RATE
<S> <C> <C> <C> <C> <C>
TGS
CUST 88.43
DEMAND CHARGE
Including 25 KW 5.50
26-900 KW 5.50
901-10000 KW 5.47
Excess Demand 5.38
Winter Demand 3.11
Reactive Demand 0.36
ENERGY CHARGE
First 82500 KWh 0.000855 - 0.000384 $0.080459
> 82500 KWh 0.000855 - 0.000384 $0.078472
> 330 KW demand 0.000855 - 0.000384 $0.078472
</TABLE>
Page 6 of 8
<PAGE> 35
APPENDIX A
ATLANTIC CITY ELECTRIC COMPANY
STIPULATION OF SETTLEMENT
1999 UNBUNDLED RATE SUMMARY
<TABLE>
<CAPTION>
TARIFF BLOCKS BGS MTC NNC TRANS DISTR DSM DECOM
$ - EQUIP/CUST ENERGY
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
SPL 1000 LUMENS-INC 1.038480 0.223430 0.689518 0.107433 3.41 1.2292 0.023 0.031
2500 LUMENS-INC 2.033791 0.437572 1.350373 0.214866 5.90 2.4043 0.045 0.060
4000 LUMENS-INC 3.292919 0.708475 2.186394 0.354529 8.14 3.8852 0.072 0.098
6000 LUMENS-INC 4.511274 0.970606 2.995344 0.483448 10.88 5.3212 0.099 0.134
3500 LUMENS-MV 1.278314 0.275031 0.848760 0.139663 5.81 1.5169 0.028 0.038
6800 LUMENS-MV 2.045783 0.440153 1.358335 0.214866 7.71 2.4246 0.045 0.061
11000 LUMENS-MV 2.870811 0.617658 1.906128 0.300812 9.76 3.3987 0.063 0.085
20000 LUMENS-MV 4.573631 0.984022 3.036747 0.483448 13.99 5.4094 0.101 0.136
35000 LUMENS-MV 7.897728 1.699205 5.243843 0.837977 22.23 9.3322 0.174 0.235
55000 LUMENS-MV 11.099510 2.388073 7.369725 1.181762 30.18 13.1104 0.244 0.330
11000 LUMENS-HPS 1.793957 0.385972 1.191131 0.193379 7.10 2.1266 0.039 0.053
30000 LUMENS-HPS 4.209084 0.905589 2.794699 0.451218 13.10 4.9791 0.092 0.125
50 WATT-HPS-COBRAHD-OVHD 0.623568 0.134161 0.414029 0.064460 6.45 0.7433 0.014 0.018
70 WATT-HPS-COBRAHD-OVHD 0.846613 0.182150 0.562125 0.085946 6.67 1.0083 0.019 0.025
100 WATT-HPS-COBRAHD-OVHD 1.177584 0.253359 0.781879 0.128919 6.96 1.3997 0.026 0.035
150 WATT-HPS-COBRAHD-OVHD 1.693227 0.364300 1.124249 0.182636 7.52 2.0091 0.037 0.050
250 WATT-HPS-COBRAHD-OVHD 2.971541 0.639331 1.973010 0.311555 10.60 3.5202 0.065 0.088
400 WATT-HPS-COBRAHD-OVHD 4.633590 0.996922 3.076558 0.494191 12.09 5.4714 0.102 0.138
150 WATT-HPS-SHOEBOX-OVHD 1.693227 0.364300 1.124249 0.182636 9.25 2.0120 0.037 0.050
250 WATT-HPS-SHOEBOX-OVHD 2.971541 0.639331 1.973010 0.311555 11.88 3.5235 0.065 0.088
400 WATT-HPS-SHOEBOX-OVHD 4.633590 0.996922 3.076558 0.494191 13.55 5.4777 0.102 0.138
50 WATT-HPS-POSTTOP-OVHD 0.623568 0.134161 0.414029 0.064460 7.17 0.7437 0.014 0.018
100 WATT-HPS-POSTTOP-OVHD 1.177584 0.253359 0.781879 0.128919 7.73 1.4006 0.026 0.035
150 WATT-HPS-POSTTOP-OVHD 1.693227 0.364300 1.124249 0.182636 9.08 2.0117 0.037 0.050
150 WATT-HPS-FLOOD-OVHD 1.693227 0.364300 1.124249 0.182636 7.35 2.0087 0.037 0.050
250 WATT-HPS-FLOOD-OVHD 2.971541 0.639331 1.973010 0.311555 9.20 3.5157 0.065 0.088
400 WATT-HPS-FLOOD-OVHD 4.633590 0.996922 3.076558 0.494191 11.65 5.4689 0.102 0.138
400 WATT-MH-FLOOD-OVHD 4.633590 0.996922 3.076558 0.494191 14.46 5.4815 0.102 0.138
1000 WATT-MH-FLOOD-OVHD 10.878863 2.340600 7.223222 1.160275 24.25 12.8193 0.239 0.323
50 WATT-HPS-COBRAHD-UGRD 0.623568 0.134161 0.414029 0.064460 9.99 0.7443 0.014 0.018
70 WATT-HPS-COBRAHD-UGRD 0.846613 0.182150 0.562125 0.085946 10.21 1.0099 0.019 0.025
100 WATT-HPS-COBRAHD-UGRD 1.177584 0.253359 0.781879 0.128919 10.49 1.4028 0.026 0.035
150 WATT-HPS-COBRAHD-UGRD 1.693227 0.364300 1.124249 0.182636 11.06 2.0142 0.037 0.050
250 WATT-HPS-COBRAHD-UGRD 2.971541 0.639331 1.973010 0.311555 13.26 3.5265 0.065 0.088
400 WATT-HPS-COBRAHD-UGRD 4.633590 0.996922 3.076558 0.494191 14.74 5.4824 0.102 0.138
150 WATT-HPS-SHOEBOX-UGRD 1.693227 0.364300 1.124249 0.182636 12.79 2.0158 0.037 0.050
250 WATT-HPS-SHOEBOX-UGRD 2.971541 0.639331 1.973010 0.311555 15.42 3.5304 0.065 0.088
400 WATT-HPS-SHOEBOX-UGRD 4.633590 0.996922 3.076558 0.494191 17.09 5.4901 0.102 0.138
50 WATT-HPS-POSTTOP-UGRD 0.623568 0.134161 0.414029 0.064460 8.84 0.7441 0.014 0.018
100 WATT-HPS-POSTTOP-UGRD 1.177584 0.253359 0.781879 0.128919 9.40 1.4021 0.026 0.035
150 WATT-HPS-POSTTOP-UGRD 1.693227 0.364300 1.124249 0.182636 12.82 2.0158 0.037 0.050
150 WATT-HPS-FLOOD-UGRD 1.693227 0.364300 1.124249 0.182636 11.68 2.0148 0.037 0.050
250 WATT-HPS-FLOOD-UGRD 2.971541 0.639331 1.973010 0.311555 13.51 3.5271 0.065 0.088
400 WATT-HPS-FLOOD-UGRD 4.633590 0.996922 3.076558 0.494191 15.18 5.4840 0.102 0.138
400 WATT-MH-FLOOD-UGRD 4.633590 0.996922 3.076558 0.494191 18.08 5.4927 0.102 0.138
1000 WATT-MH-FLOOD-UGRD 10.878863 2.340600 7.223222 1.160275 27.85 12.8414 0.239 0.323
ORN STANDARDS-BEFORE 1-17-86 - - - - 0.57 - - (0.000)
NON-ORN STANDARDS-AFTER 1-17-86 - - - - 0.83 - - (0.000)
</TABLE>
<TABLE>
<CAPTION>
TARIFF BLOCKS UNCOLL. REG TOTAL
ACCTS. ASSETS RATE
<S> <C> <C> <C> <C>
SPL 1000 LUMENS-INC - 0.011 6.77
2500 LUMENS-INC - 0.032 12.48
4000 LUMENS-INC - 0.043 18.78
6000 LUMENS-INC - 0.064 25.46
3500 LUMENS-MV - 0.021 9.95
6800 LUMENS-MV - 0.032 14.33
11000 LUMENS-MV - 0.043 19.04
20000 LUMENS-MV - 0.064 28.78
35000 LUMENS-MV - 0.107 47.75
55000 LUMENS-MV - 0.150 66.06
11000 LUMENS-HPS - 0.021 12.90
30000 LUMENS-HPS - 0.054 26.71
50 WATT-HPS-COBRAHD-OVHD - 0.011 8.48
70 WATT-HPS-COBRAHD-OVHD - 0.011 9.41
100 WATT-HPS-COBRAHD-OVHD - 0.011 10.77
150 WATT-HPS-COBRAHD-OVHD - 0.021 13.00
250 WATT-HPS-COBRAHD-OVHD - 0.043 20.21
400 WATT-HPS-COBRAHD-OVHD - 0.064 27.07
150 WATT-HPS-SHOEBOX-OVHD - 0.021 14.73
250 WATT-HPS-SHOEBOX-OVHD - 0.043 21.50
400 WATT-HPS-SHOEBOX-OVHD - 0.064 28.54
50 WATT-HPS-POSTTOP-OVHD - 0.011 9.19
100 WATT-HPS-POSTTOP-OVHD - 0.011 11.55
150 WATT-HPS-POSTTOP-OVHD - 0.021 14.57
150 WATT-HPS-FLOOD-OVHD - 0.021 12.83
250 WATT-HPS-FLOOD-OVHD - 0.043 18.80
400 WATT-HPS-FLOOD-OVHD - 0.064 26.62
400 WATT-MH-FLOOD-OVHD - 0.064 29.44
1000 WATT-MH-FLOOD-OVHD - 0.150 59.39
50 WATT-HPS-COBRAHD-UGRD - 0.011 12.02
70 WATT-HPS-COBRAHD-UGRD - 0.011 12.95
100 WATT-HPS-COBRAHD-UGRD - 0.011 14.30
150 WATT-HPS-COBRAHD-UGRD - 0.021 16.55
250 WATT-HPS-COBRAHD-UGRD - 0.043 22.88
400 WATT-HPS-COBRAHD-UGRD - 0.064 29.73
150 WATT-HPS-SHOEBOX-UGRD - 0.021 18.28
250 WATT-HPS-SHOEBOX-UGRD - 0.043 25.04
400 WATT-HPS-SHOEBOX-UGRD - 0.064 32.08
50 WATT-HPS-POSTTOP-UGRD - 0.011 10.87
100 WATT-HPS-POSTTOP-UGRD - 0.011 13.22
150 WATT-HPS-POSTTOP-UGRD - 0.021 18.31
150 WATT-HPS-FLOOD-UGRD - 0.021 17.17
250 WATT-HPS-FLOOD-UGRD - 0.043 23.13
400 WATT-HPS-FLOOD-UGRD - 0.064 30.17
400 WATT-MH-FLOOD-UGRD - 0.064 33.08
1000 WATT-MH-FLOOD-UGRD - 0.150 63.01
ORN STANDARDS-BEFORE 1-17-86 - - 0.57
NON-ORN STANDARDS-AFTER 1-17-86 - - 0.83
</TABLE>
Page 7 of 8
<PAGE> 36
<TABLE>
<CAPTION>
TARIFF BLOCKS BGS MTC NNC TRANS DISTR DSM DECOM
$ - EQUIP/CUST ENERGY
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
POSTS - - - - 0.20 - - (0.000)
CSL
HPS50 0.623568 (0.263325) 0.414029 0.064460 2.65 0.7397 0.014 0.019
HPS70 0.846613 (0.357515) 0.562125 0.085946 2.87 1.0029 0.019 0.025
HPS100 1.177584 (0.497280) 0.781879 0.128919 3.17 1.3903 0.026 0.035
HPS150 1.693227 (0.715029) 1.124249 0.182636 3.74 1.9953 0.037 0.050
HPS250 2.971541 (1.254846) 1.973010 0.311555 5.00 3.4881 0.065 0.088
HPS400 4.633590 (1.956710) 3.076558 0.494191 6.50 5.4215 0.102 0.138
STANDARDS - - - - (0.01) 5.8908 - (0.000)
DDC
Service and Demand - 0.099679 - 0.000838 0.223678 - 0.000173 0.000234
Energy 0.009976 0.585386 0.005235 0.000838 1.576590 - 0.0002 0.0002
<CAPTION>
TARIFF BLOCKS UNCOLL. REG TOTAL
ACCTS. ASSETS RATE
<S> <C> <C> <C> <C>
POSTS - - 0.20
CSL
HPS50 - 0.011 4.27
HPS70 - 0.011 5.07
HPS100 - 0.011 6.22
HPS150 - 0.021 8.13
HPS250 - 0.043 12.68
HPS400 - 0.064 18.48
STANDARDS - (0.000) 5.89
DDC
Service and Demand - 0.00011 0.324710
Energy - 0.00011 2.178539
</TABLE>
Page 8 of 8
<PAGE> 37
SCHEDULE A
ATLANTIC CITY ELECTRIC COMPANY
STIPULATION OF SETTLEMENT
<TABLE>
<CAPTION>
ESTIMATED
AMOUNTS
$ (000)
---------
<S> <C>
REGULATORY CREDITS:
ANTICIPATED LEAC OVER RECOVERY @ 7/31/99 $ 44,409
ANTICIPATED DSM UNDER SPENDING @ 7/31/99 $ 6,949
--------
TOTAL DOLLARS AVAILABLE $ 51,358
========
REGULATORY ASSETS:
ESTIMATED GRFT BALANCE @ 7/31/99 $ 30,017
ESTIMATED SUSQUEHANNA BALANCE @ 7/31/99 $ 20,008
--------
TOTAL UNAMORTIZED BALANCE $ 50,025
========
CORRESPONDING REDUCTION IN
REGULATORY ASSET CHARGES:
REMOVE GRFT FROM BASE RATES $ 13,546
REMOVE SUSQUEHANNA FROM BASE RATES $ 22,389
--------
TOTAL RATE REDUCTION $ 35,935
========
</TABLE>
<PAGE> 38
SCHEDULE B
ATLANTIC CITY ELECTRIC COMPANY
STIPULATION OF SETTLEMENT
Transferred Units
<TABLE>
<CAPTION>
STATION / UNITS FUEL UNIT
CAPACITY (MW)
<S> <C> <C>
Missouri Ave. CT's
Unit B Oil 20
Unit C Oil 20
Unit D Oil 20
---
SUBTOTAL M/A CT'S 60
Carl's Corner CT's
Unit 1 Gas/Oil 37
Unit 2 37
---
SUBTOTAL CC CT'S 74
Cedar CT's
Unit 1 Oil 46
Unit 2 Oil 22
---
SUBTOTAL CEDAR CT'S 68
Middle CT's
Unit 1 Oil 20
Unit 2 Oil 20
Unit 3 Oil 37
---
SUBTOTAL MIDDLE CT'S 77
Cumberland CT Gas/Oil 84
Sherman Ave. CT Gas/Oil 81
Mickleton CT Gas/Oil 59
Deepwater CT Gas/Oil 20
---
SUBTOTAL CT'S 523
===
Deepwater Steam Units
Unit 1
Unit 4 Oil 86
Unit 6/8 Oil 54
Coal 80
---
SUBTOTAL STEAM UNITS 220
===
TOTAL TRANSFERRED UNITS CAPACITY 743
===
</TABLE>
<PAGE> 39
SCHEDULE C
ATLANTIC CITY ELECTRIC COMPANY
STIPULTION OF SETTLEMENT
<TABLE>
<CAPTION>
RESTRUCTURING - RELATED ESTIMATED
CAPITAL EXPENDITURES: COSTS
$(000)
------
<S> <C>
CUSTOMER CARE SYSTEM ENHANCEMENTS $4,323
BALANCING & SETTLING SYSTEM $ 260
LOAD STUDY PROJECT FOR LOAD PROFILES $ 860
------
TOTAL CAPITAL EXPENDITURES $5,443
======
</TABLE>
<PAGE> 40
SCHEDULE D
ATLANTIC CITY ELECTRIC COMPANY
STIPULATION OF SETTLEMENT
<TABLE>
<CAPTION>
RESTRUCTURING - RELATED ESTIMATED
O&M EXPENDITURES: COSTS
$000
----
<S> <C>
REGULATORY PROCEEDINGS $ 6,566
CONTINUING OPERATIONS RELATED
TO RETAIL CHOICE:
CUSTOMER CARE $ 9,198
BALANCING & SETTLEMENT $ 520
LOAD PROFILING $ 250
-------
TOTAL O & M EXPENDITURES $16,534
=======
</TABLE>
