Exhibit (99)(b)
STATE OF MICHIGAN
BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION
In the matter, on the Commission's own )
motion, to consider the restructuring of ) Case No. U-11290
the electric utility industry )
_____________________________________________)
RESPONSE OF CONSUMERS ENERGY COMPANY
TO COMMISSION REQUEST FOR INFORMATION
March 7, 1997
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TABLE OF CONTENTS
Page
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I. INTRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . . 1
II. RESPONSE TO COMMISSION REQUEST . . . . . . . . . . . . . . . . 3
Question 1: A detailed calculation of anticipated
stranded costs, including possible
mitigation measures, and transition
charges given the definition in the
Staff Report. The utility should also
provide information on any alternative
method of calculating stranded cost
that it has developed . . . . . . . . . . . . . . 3
A. Determination of Transition Costs . . . . . . . . . . . 3
1. Regulatory Assets . . . . . . . . . . . . . . . . 4
2. Nuclear Facilities . . . . . . . . . . . . . . . 7
3. Decommissioning of Hydroelectric and Pumped
Storage Facilities . . . . . . . . . . . . . . . 8
4. Contract Capacity Charges . . . . . . . . . . . . 9
5. Employee-Related Restructuring Costs . . . . . . 11
6. Other Implementation Costs . . . . . . . . . . . 12
B. Determination of Transition Charges . . . . . . . . . . 13
C. Mitigation . . . . . . . . . . . . . . . . . . . . . . . 14
Question 2: The items the utility would expect to
securitize if authorized to do so, and an
analysis regarding the anticipated
financial and rate effects . . . . . . . . . . . 17
Question 3: A description of how the utility would
allocate direct access capacity, including
procedures for bidding and aggregation.
The utility should also indicate any
appropriate alternatives to the phase-in
schedule . . . . . . . . . . . . . . . . . . . . 21
A. Allocation . . . . . . . . . . . . . . . . . . . . . . . 21
B. Bidding . . . . . . . . . . . . . . . . . . . . . . . . 22
C. Aggregation . . . . . . . . . . . . . . . . . . . . . . 22
D. Alternatives to the Phase-In Schedule . . . . . . . . . 23
Question 4: Tariff sheets for direct access service,
with supporting workpapers and applicable
FERC tariffs . . . . . . . . . . . . . . . . . . 24
Question 5: A description, including tariff sheets, for
the standby service that the utility would
provide to direct access customers . . . . . . . 26
Question 6: A list of any new or additional
charges that the utility does not
currently assess that would be imposed
under a direct access program . . . . . . . . . . 27
Question 7: A description of any transmission
constraints or limitations on the ability
to import power into the utility's system.
This description should include: (a) the
amount of electricity currently being
imported into the system from Michigan
sources and from outside the state; (b) the
nature of the existing imports, e.g.,
wholesale transactions; (c) the nature and
location of the constraints; (d) an
estimate of the amount of direct access
electricity that could be imported into the
utility's system given existing
constraints; and (e) methods of removing
constraints and their estimated costs and
effects . . . . . . . . . . . . . . . . . . . . . 29
Question 8: The status of any ongoing discussions
regarding the development of an
Independent System Operator . . . . . . . . . . . 31
Question 9: A description of the methods that the
utility would propose to alleviate
concerns regarding market power in a
competitive market . . . . . . . . . . . . . . . 34
III. SUMMARY OF ESSENTIAL FEATURES OF RESTRUCTURING PLAN . . . . . 40
A. Retail Direct Access Schedule . . . . . . . . . . . . . . . 40
B. Allocation and Bidding . . . . . . . . . . . . . . . . . . 40
C. Transition Cost Recovery . . . . . . . . . . . . . . . . . 41
D. Rates, Terms and Conditions of Retail Direct
Access Service . . . . . . . . . . . . . . . . . . . . . . 42
E. Rate Freeze . . . . . . . . . . . . . . . . . . . . . . . . 42
F. PSCR Suspension . . . . . . . . . . . . . . . . . . . . . . 42
G. Performance-Based Ratemaking Mechanism . . . . . . . . . . 44
H. Obligation To Serve . . . . . . . . . . . . . . . . . . . . 44
I. Reciprocity . . . . . . . . . . . . . . . . . . . . . . . . 45
J. Creation of an Independent System Operator . . . . . . . . 46
IV. CONCLUSION . . . . . . . . . . . . . . . . . . . . . . . . . 46
Attachment 1
Attachment 2
Attachment 3
Attachment 4
Attachment 5
Attachment 6
Attachment 7
Attachment 8
STATE OF MICHIGAN
BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION
In the matter, on the Commission's own )
motion, to consider the restructuring of ) Case No. U-11290
the electric utility industry )
_____________________________________________)
RESPONSE OF CONSUMERS ENERGY COMPANY
TO COMMISSION REQUEST FOR INFORMATION
I. INTRODUCTION
On December 20, 1996, the Commission initiated this proceeding
to review a report on electric industry restructuring which had been
prepared by the MPSC Staff ("Staff Report"). On January 21, 1997,
Consumers Energy Company ("Consumers Energy"), along with many other
parties, filed comments on the Staff Report. The Commission also held
several public hearings at which additional comments were received.
On February 5, 1997, the Commission issued an "Order Requesting
Comments and Notice of Hearing" ("February 5 Order"). In that order, the
Commission requested Consumers Energy and The Detroit Edison Company
("Detroit Edison") (and any other electric utilities who so desire) to
make, by March 7, 1997, additional filings which would address in greater
detail how the recommendations in the Staff Report could be implemented.
The order includes a list of specific questions which the Commission
requested the utilities to address. This is Consumers Energy's Response
to the Commission's request.
In preparing this Response, Consumers Energy has provided the
Commission not only with information which is responsive to the questions
asked, but also with a detailed program for the initial implementation of
the Staff plan. As set forth in its January 21, 1997 Comments, Consumers
Energy continues to be willing to voluntarily implement the retail direct
access program set forth in this submission, subject to (i) the Commission
approving the entirety of the plan set forth herein, and (ii) the
Commission specifically approving the calculation of transition costs and
the associated charges set forth below. In addition, because it is
essential to gain legislative authorization of the restructuring plan, the
Company's willingness to voluntarily implement this plan will cease as of
December 31, 1997, unless appropriate utility restructuring legislation
has been enacted by the Legislature and signed into law by that date.
Upon completing its review of the March 7 filings and other parties
comments, the Company hopes that the Commission will issue an order (1)
endorsing the Staff plan as further developed in this Response, (2)
recommending to the Legislature the enactment of legislation which is
consistent with that plan, and (3) accepting the Company's offer of
voluntary implementation.
The Company emphasizes that since the issuance of the February 5
Order, it has done considerable analysis of the transition cost and
securitization features of the Staff's proposed restructuring plan in an
effort to be fully responsive to the Commission's inquiries. Consumers
Energy now believes that securitization offers significantly greater
customer benefits than were previously identified. Specifically,
securitization offers over a $200 million annual savings to customers
compared to the rates which customers would otherwise pay. This is
discussed in greater detail below.
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II. RESPONSE TO COMMISSION REQUESTS
This portion of the Company's Response addresses the specific
information requests made by the Commission in the February 5 Order.
Question 1: A detailed calculation of anticipated stranded
costs, including possible mitigation measures,
and transition charges given the definition in
the Staff Report. The utility should also
provide information on any alternative method of
calculating stranded cost that it has developed.
A. Determination of Transition Costs
The critical element of electric utility restructuring is the
provision to regulated electric utilities of a reasonable opportunity to
recover: (i) costs associated with investments and commitments that were
made during the regulated era which will be above prevailing near term
market prices in a competitive environment, and (ii) costs that are
incurred to facilitate the transition from regulated market status to
competitive market status. The Staff Report properly recognizes that:
"[t]he opportunity to recover transition costs is
necessary to assure a fair, smooth, and realizable
restructuring of the electric industry. Without
reasonable recovery of transition costs, significant
adverse and unacceptable impacts on various interested
parties will occur. In short, reasonable recovery of
transition costs helps to assure financially healthy
utilities and reliable electric service in the State."
Staff Report, p. 13.
The definition of transition costs adopted by the Staff in its
report includes the following categories:
1. Regulatory assets approved for cost recovery by the
Commission;
2. The net book capital costs of nuclear facilities;
3. The contract capacity charges included in long-term power
purchase agreements, to the extent those charges have
already been approved for cost recovery by the Commission,
and to the extent those charges exceed the estimated near
term market value of the associated capacity;
4. Employee-related restructuring costs;
5. Other costs related to the implementation of industry
restructuring, such as the creation and implementation of
new metering and billing systems, and the establishment of
an independent system operator.
In addition, Consumers Energy believes that the decommissioning
costs associated with the Ludington Pumped Storage Plant and other hydro
facilities should be added to the list. These facilities are licensed by
the Federal Regulatory Energy Commission ("FERC"). Similar to federal law
governing nuclear plants, the FERC requires hydro electric and pumped
storage sites to be decommissioned at the end of their useful lives.
Including these decommissioning costs in the category of transition costs
is, in Consumers Energy's opinion, consistent with the Staff's approach to
this issue.
Consumers Energy believes the above categories of costs provide
a reasonable means of analyzing and measuring transition costs. The bulk
of these items represent costs that, pursuant to the current regulated
industry structure, have already been subjected to regulatory scrutiny,
and have been found to be properly recoverable from customers. Categories
4 and 5 represent costs that will have to be incurred in the future in
order to move to the competitive industry structure envisioned by the
Staff Report. Each of these categories are quantified and discussed
below. Except where specifically noted, the costs identified in this
response reflect only those costs which Consumers Energy will incur during
the 1997-2007 time period; i.e., costs expected to be incurred beyond 2007
are not included in this analysis.
1. Regulatory Assets
The individual items and the associated dollar amounts within
this category are listed below. It should be noted that the dollar
amounts listed are stated in nominal dollars, and are only the estimated
generation-related portion of each item which will be stated on Consumers
Energy's books as of December 31, 1997.
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Table 1
Item $(million)
A. The remaining Midland 3B amortization amount 86.6
first authorized in Case No. U-7830.
B. The remaining SFAS 106 (other post 97.2
employment benefits) obligation, first
authorized in Case No. U-10335.
C. The remaining Demand Side Management 42.5
("DSM") costs approved for recovery in
Cases No. U-9346, U-10335 and U-10685.
D. The remaining Department of Energy 19.5
assessment for decontamination and
decommissioning of enrichment facilities
most recently authorized in Case No. U-10445.
E. Previously flowed through income tax 49.0
benefits (SFAS 109) first authorized in
Case No. U-10083.
F. The remaining Ludington Settlement 12.3
amortization amount approved for recovery
in Case No. U-10685.
G. Refunded debt costs approved for recovery
in Case No. U-10685. 4.5
______
Total--Regulatory Assets $311.6
Under current rates, these items would all be fully amortized on
Consumers Energy's books before 2007, except for item B (SFAS 106), item E
(SFAS 109) and item G (refunded debt). The recovery period for these
three items under current rates extends to 2011, 2016, and 2010,
respectively.
It must be noted that the dollar amounts identified in Table 1
reflect the entire generation-related amount of these regulatory assets as
of December 31, 1997. Given the Staff phase-in schedule, however, a
substantial portion of these costs will be paid by non-retail access
customers via bundled rates. Based upon the Staff phase-in schedule, the
appropriate dollar amount recoverable through the transition charge is the
present value amount associated with only the retail direct access load,
or $70.3 million. See Attachment 1.(1)
Consumers Energy does not believe extended discussion of each of
these items is necessary, or was contemplated by the Commission's
February 5 Order. These are all cost items that have previously been
approved for recovery from customers by the Commission, and are currently
included in rates, but which, in the absence of appropriate ratemaking
treatment, would not be recovered from customers who engage in retail
direct access. Indeed, the Commission has already formally determined
that these types of costs are properly recoverable from customers who
engage in retail direct access. See June 19, 1995 Order in Cases No. U-
10143/U-10176 and November 14, 1996 Order in Cases No. U-10685/U-10787/U-
10754. The Staff's recommendations that these items should be included as
transition costs, and that retail direct access customers should continue
to pay their share of these costs, is just and reasonable.
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(1)Attachment 1 shows the detailed calculations and assumptions which
underlie the transition cost and securitization figures discussed in this
Response.
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2. Nuclear Facilities
The total net book cost of Consumers Energy's two nuclear units
which are projected to be stated on the Company's books as of December 31,
1997 is $552,493,000. The detail corresponding to this total is as
follows:
Table 2
Category Palisades Big Rock Total
(000) (000) (000)
Gross Plant $735,856 $65,252 $801,108
Construction 32,111 2 32,113
Work in Progress
Inventory 17,823 2,339 20,162
Accumulated (248,493) (52,397) (300,890)
Depreciation
Reserve _________ ________ _________
Net Plant $537,297 $15,196 $552,493
As noted above with respect to regulatory assets, part of the
$552.493 million figure will be recovered from non-retail access customers
over the phase-in period. Based upon the phase-in schedule recommended in
the Staff Report, the proper amount recoverable via the transition charge
is the present value amount associated with only the retail direct access
load, or $220.1 million. See Attachment 1.
Under current rates, Big Rock will be fully depreciated in 1998,
while Palisades will be fully depreciated in 2007. As stated in the Staff
Report, it is appropriate to consider the entire net book capital cost of
these nuclear units (and the associated return) in the transition cost
calculations because the near term market price of power in a competitive
environment will not likely even offset the fuel and other operating and
maintenance ("other O&M") costs associated with these units, let alone
make a contribution toward recovery of the capital costs. The average per
kilowatt-hour fuel/other O&M cost at Palisades is approximately 2.9 cents.
There are also substantial continuing capital investment requirements
associated with these units which are not reflected in the above figures.
For example, the average annual capital expenditure at Palisades in 1994
and 1995 was $33 million. Under the approach recommended by the Staff,
Consumers Energy will be at risk for the recovery of all future nuclear
plant capital additions, as well as of ongoing fuel and other O&M
expenses. It may be noted that this approach stands in contrast to that
being followed in California, where the recently enacted legislation
creates a procedure which allows for recovery of nuclear plant capital
additions for a period extending through the end of the transition cost
recovery period (i.e., December 31, 2001 under California's plan). See
1996 Cal. AB. 1890, Section 367.
3. Decommissioning of Hydroelectric
and Pumped Storage Facilities
Consumers Energy owns and operates eleven hydroelectric
facilities, as well as a 51% ownership interest in the Ludington Pumped
Storage Plant. As is the case with the Company's nuclear generating
units, these units will have to be decommissioned at the end of their
useful lives. The currently estimated costs of decommissioning these
facilities are reflected in the depreciation rates which the Commission
has approved, and are included in the Company's rates. Since these units
were constructed to serve the Company's entire customer base, customers
electing retail access should be required to pay their share of these
decommissioning costs.
Under current rates, the Ludington Plant is expected to be
retired and decommissioned in 2028. The corresponding date for the eleven
hydro plants is 2034. The appropriate amount to be reflected in the
transition cost calculation for this item was determined based upon the
present value of the revenues which would otherwise be collected in rates
for decommissioning of these units in the absence of a retail access
program. The appropriate amount is $16,174,000. See Attachment 1.
4. Contract Capacity Charges
Consumers Energy has a substantial number of power purchase
agreements with non-utility generators ("NUG's") pursuant to which it
purchases nearly 1700 megawatts of capacity. All of the power so
purchased has been and continues to be used to serve customers. All of
these NUG's are qualifying facilities, as that term is defined in the
Public Utility Regulatory Policies Act of 1978 ("PURPA"). As the
Commission is, of course, aware, PURPA was the U.S. Congress' policy
response to the claimed "energy crisis" of the 1970's. That act obligated
electric public utilities to purchase power supplied by qualifying
facilities at rates that reflected the purchasing utility's "avoided
cost," as determined by state regulatory bodies. Pursuant to PURPA's
mandate, and due to Consumers Energy's need for additional generating
capacity at that time, the Company entered into these power purchase
agreements beginning in 1983. Additional qualifying facility agreements
were entered into in connection with a Commission-approved settlement of
various disputes in 1993. Finally, in compliance with the directives of
the Michigan legislature as set forth in 1989 PA 2, which obligated
Consumers Energy to enter into contracts for 120 megawatts of capacity
from "waste-to-energy" facilities, the Company signed additional power
purchase agreements in 1993. See Attachment 2 for a list of NUG contracts
and Commission orders in which cost recovery of contract capacity charges
has been approved. The capacity and energy charges contained in these NUG
contracts were determined according to methodologies which were approved
by the Commission, and reflect estimates of Consumers Energy's avoided
costs determined at the time the contracts were signed. The costs
associated with these power purchase agreements have been approved for
recovery through Consumers Energy's rates in orders issued from 1984
through 1996.
In other states which are also in the process of restructuring
the electric utility industry, it has uniformly been recognized that the
costs associated with purchases from PURPA qualifying facilities pursuant
to contracts entered into over the past 10-15 years will exceed the market
price of power in a competitive marketplace, at least over the near term,
and that such costs should be recoverable as a component of transition
costs. The recently-enacted Pennsylvania legislation states that the
Pennsylvania Commission "shall allow" recovery of "cost obligations under
contracts with non-utility generating projects that have received a
commission order. . . ." See 1995 Pa. Laws 138, Title 66, Chapter 28.
The California legislation provides for recovery of "power purchase
contract obligations", along with recovery of "costs associated with any
buy-out, buy-down, or renegotiation" of those contracts. See 1996 Cal.
AB. 1890. The Rhode Island legislation also provides for such recovery.
See 1996 R.I. Pub. Laws, Chapter 316.
The Staff Report similarly recognizes that the contract
obligations of the purchasing utility which resulted from the
implementation of the legislative directives contained in PURPA and 1989
PA 2 must be dealt with in any realistic restructuring plan. The
recommendation of the Staff would leave the purchasing utility at risk for
recovery of the energy charge (both fixed and variable) and for the
estimated near term market value of the capacity in an open access
competitive market. The remaining contract costs would be recoverable as
part of total transition costs. Based upon the capital costs associated
with the construction and maintenance of a gas peaking unit built to
provide standby service in an open access environment, the near term
market value for purposes of this calculation would approximate 0.5
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cents per kWh.(2) Based upon (i) this 0.5 cents per kWh figure, and
(ii) the anticipated purchases from NUG contracts over the 1997-2007
period, the total present value amount of contract capacity costs in
excess of this value is approximately $3,194.9 million. For the same
reasons noted earlier with respect to regulatory assets and nuclear
facilities, the present value amount of these costs associated with retail
direct access load, based upon the Staff phase-in schedule, is $1,459
million. See Attachment 1.
5. Employee-Related Restructuring
Costs
The transition to a competitive generation market will require
many changes in the way electric utilities conduct business. Many of
these changes will undoubtedly affect the amount and nature of staffing
requirements in the various segments of the utility's current business
operations. The California legislation recognized that this would occur,
and explicitly stated that costs associated with employee severance,
retraining programs, early retirement programs, out placement programs and
similar items should be included in recoverable transition costs. The
Staff Report similarly recognized that such costs should be recoverable,
and further recommended that some means of auditing and verifying such
costs should be implemented.
Consumers Energy currently estimates that such costs would
approximate $50 million over the 1998-2002 time period. These costs
should be added to the total transition costs
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(2)Consumers believes 0.5 cents/kWh is a reasonable near term
assumption for the value of capacity based on the following reference
points:
* Current estimates for construction of new simple cycle gas turbine
generation facilities range from $250-$350/kW. While fixed charge
rate and load factor assumptions affect the cents/kWh rate which
results from such facility costs, this range is consistent with 0.5
cents/kWh.
* In other countries such as Great Britain and Argentina which have
already deregulated generation, the value of capacity has settled at
approximately 0.5 cents/kWh.
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used to calculate the appropriate initial transition charge, and should be
subject to periodic review and adjustment to the extent actual employee-
related restructuring costs are different than this estimate.
6. Other Implementation Costs
The implementation of any meaningful restructuring plan will
require the expenditure of significant sums for new billing systems, new
computer systems infrastructure to accommodate changes in metering
equipment, the establishment of an independent system operator and other
similar items. For example, the technology needed to gather and
communicate the information necessary to allow large scale retail direct
access includes the installation of communication equipment on customer
meters, infrastructure investment needed to transmit the customer
information gathered at the meter, and computer hardware/software
investment necessary to process the information for use in preparing
bills. In addition, a completely new billing system must ultimately be
developed to accommodate unbundled pricing, and the preparation of bills
containing multiple pricing structures from multiple suppliers of
generation services and other services.(3) Additional investments will
also be necessary to implement an automated power transactions scheduling
system, along with the costs of developing and implementing an independent
transmission system operator system. Consumers Energy currently estimates
that such costs will be $150 million over the 1998-2002 time period.
These costs should be added to the total transition costs used to
calculate the appropriate transition charge, and should be subject to
periodic review and adjustment to the extent actual costs are different
than this estimate.
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(3)A general description of the activities necessary to develop and
install the technology improvements needed to implement retail direct
access, as well as a potential schedule for those activities, is provided
as Attachment 3.
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B. Determination of Transition Charges
Based upon the above cost determinations, transition and
implementation charges were developed which would be applicable only to
those customers electing retail direct access service during the 1997-2007
time period. The basic assumptions underlying the calculation of the
charge, and the details of the calculation are set forth on Attachment 1.
In summary, this approach:
(i) Reflects only those costs to be incurred (or amortized)
over the 1998-2007 time period. The only exceptions to this are, as
noted above, the SFAS 106, SFAS 109 and refunded debt regulatory
assets, which, under current rates, would be amortized over periods
extending to 2011, 2016, and 2010, respectively, and the Ludington
and hydro plant decommissioning cost.
(ii) Calculates a per kWh charge based upon the October 1996
sales forecast for the 1998-2007 time period.
(iii) Reflects a $4.9 million reduction in total transition
costs based upon the assumption that a portion of the payments made
by Rate DA participants during 1998-2000 will allow recovery of a
portion of total transition costs.
(iv) Assumes the schedule for retail direct access set forth in
the Staff Report is followed, and calculates the load associated with
the customers opting for retail direct access pursuant to that
schedule.
(v) Uses the overall pre-tax rate of return approved in the
most recent electric rate order of 10.63%, (see February 5, 1996
Order in Case No. U-10685), and a 7% discount rate to determine the
present value of future revenues.
(vi) Develops a levelized transition charge which would be
applicable for the entire 1998-2007 time period, only for those
customers eligible for retail direct access. Other customers are
assumed to continue to pay bundled rates during this period.
Similarly, the implementation charge (covering employee-related and
other restructuring costs) would also apply only to retail access
customers.
(vii) Assumes that all nuclear decommissioning costs
continue to be recovered through a separate charge applicable to all
customers.
The levelized transition charge (i.e., for recovery of the costs
associated with regulatory assets, Ludington/hydro decommissioning,
nuclear facilities and power purchase agreements) which results from this
approach is 1.31 cents per kWh. The levelized implementation charge (i.e.,
for recovery of employee-related restructuring costs and other
implementation costs) is 0.14 cents per kWh. The total charge is 1.45
cents per kWh. See Attachment 1. This is the charge that would apply in
the absence of securitization.
Because the above calculations are based upon a relatively long-
term sales forecast, it is essential to periodically "true-up" the
collection of these amounts to reflect actual sales levels. Neither
utilities nor customers should be put at risk for factors such as the
performance of the Michigan economy and weather over a ten year period.
Thus, the charges should be adjusted on January 1, 2001 and January 1,
2004 to reflect what actual sales levels have been. There would be no
true-ups for any other factors.
C. Mitigation
The February 5 Order asked the utilities to address to what
degree transition cost mitigation measures are reflected in the Staff
recommendation. There are numerous examples of such mitigation measures
which are inherent in the Staff Report. These include the following:
(A) During the transition period, the above-described
calculation of transition costs effectively assumes that, for the
load lost to third party power suppliers, the Company will be able to
sell the displaced generation to some other buyer at a price at least
equal to market value. The inability to do so would mean that the
estimate of transition (or stranded) costs set forth above is
significantly understated. Thus, there is a business risk associated
with being able to negotiate transactions which allow those sales to
take place. This also highlights the importance of the reciprocity
condition which the Staff Report properly recommends. Without the
ability to sell into other utilities' markets, Consumers Energy's
generation would effectively be land-locked, and its transition costs
would be substantially increased.
(B) The utility assumes all risk associated with the
recoverability of existing and future capital costs of its fossil and
hydro electric generating units. The current net book value of these
units on Consumers Energy's books is over $800 million (excluding
CWIP and inventories). Average annual capital expenditures for
these units during 1993-1995 was approximately $40 million. The rate
freeze recommended by the Staff will prevent recovery of any capital
additions during the transition period, and the Company will be
solely at risk for the recovery of all capital, fuel and other O&M
costs after the full phase-in of retail direct access.
(C) The utility also assumes all risk associated with the
recoverability of the fuel, and other O&M expenses associated with
its fossil and hydro units. The rate freeze (and PSCR suspension)
recommended by the Staff would prevent recovery of any increases in
these costs during the transition period, and the Company would be
fully at risk for recovery of all of these costs after the phase-in
of direct access.
(D) As was noted earlier, the utility assumes all risk
associated with future capital additions for its nuclear units. The
substantial regulatory requirements associated with the operation of
these units makes this a particularly significant risk.
(E) The utility also assumes all risk associated with the
recoverability of nuclear fuel, and nuclear other O&M expenses for
these units. The level of these costs recoverable through rates is
frozen during the transition period, and is recoverable only to the
extent the market permits recovery thereafter.
(F) The above calculations cover only the period through
December 31, 2007. This limitation also applies to the NUG
agreements, even though the terms of all of those agreements extend
well past 2007. For purposes of this Response, Consumers Energy has
accepted the implicit conclusion in the Staff Report that market
conditions beyond 2007 are difficult to predict, and that it is
therefore appropriate to limit the calculation of NUG-related
transition costs to the 1998-2007 time period. Given the long term
nature of these power supply contracts, there are substantial
contract costs that Consumers Energy will incur beyond 2007, however,
and the recoverability of those costs will depend upon market
conditions existing at that future time, or, to the extent market
conditions do not permit such recovery, the ability to obtain
recovery of any future stranded costs via some regulatory mechanism.
The Company intends to return to the Commission for a resolution of
NUG recovery issues at that time should it appear necessary. To
attempt now to resolve questions about market conditions and economic
conditions 10 years in the future would not be productive and would
serve only to delay the availability of retail access.
(G) The utility assumes certain market, contract and regulatory
risks associated with the payment of energy charges pursuant to the
NUG agreements, since these charges could prove to be above market
prices in certain conditions.
(H) It is also appropriate to consider the phase-in strategy
included in the Staff Report as a mitigation measure. The Staff
recommended, and Consumers Energy agrees, that the transition to full
retail direct access should be phased in over a 6-7 year period.
This greatly assists in mitigating transition costs in a variety of
ways. First, it provides the utility with an opportunity to take the
organizational and management steps necessary to operate in a
deregulated, competitive environment. Second, and as mentioned
previously, an acceleration of direct access would result in an
increase in the transition cost charge described above. In addition,
the phase-in of direct access permits the large expenditures
necessary to accommodate the revised metering, billing and other
computer systems to be spread over a longer period, thereby allowing
those implementation activities to proceed in a more efficient and
cost-effective manner. Electric restructuring in Michigan should not
be allowed to fall victim to the "America ON-Line" syndrome.
(I) Because the PSCR process will be suspended, the utility
assumes the risk of variations in fuel prices, unit performance
factors, availability of third-party supplied power, and other
matters, to the extent they deviate from what is reflected in the
frozen rate.
(J) As stated in the following section, earnings of the
investment trust which exceed what is necessary to make payments to
the NUG's would be distributed to customers, thereby mitigating
transition costs.
(K) The amounts bid during the phase-in period for the ability
to participate in the retail access program will be credited against
other restructuring implementation costs, thereby mitigating those
costs.
(L) The "true-up" procedures for transition costs described
above will, to the extent actual sales growth exceeds what is
projected, serve to reduce transition costs payable by customers.
(M) It is also appropriate to recall that, with respect to the
MCV power purchase agreement, Consumers Energy has previously
incurred write-offs and other losses exceeding $700 million, which
represent savings to customers.
(N) A further potential mitigation element would be any
stranded costs recovered as a result of proceedings at the Federal
Energy Regulatory Commission. Such a proceeding is currently pending
at the FERC concerning the Alma municipalization proposal. See FERC
Docket No. SC97-4-000. Amounts recovered in this manner would serve
to reduce the transition costs otherwise authorized by this
Commission.
-17-
Question 2: The items the utility would expect to securitize
if authorized to do so, and an analysis regarding
the anticipated financial and rate effects.
Consumers Energy agrees with the Staff Report recommendation
that the securitization of transition charge revenues should be seriously
explored. This approach offers a potentially valuable tool in an electric
utility restructuring package. Securitization would permit the recovery
of transition costs, while doing so in a manner which provides rate
benefits to current customers. This approach can thereby provide
significant benefits to customers and all interested parties. While the
Legislature must ultimately authorize this securitization approach, the
Commission has an essential role to play. Consumers Energy urges the
Commission to explicitly endorse this feature of the Staff Report as an
important element to be included in restructuring legislation and to adopt
the calculations and charges which are set forth in this Response.
While the Company's analysis of the securitization option is
still continuing(4), at this time it expects that the following items and
associated dollar amounts would provide the basis for the revenue stream
to be securitized:(5)
- ---------------------
(4)It should be noted that the Company's presentation in this
Response regarding securitization assumes that the proceeds derived from
the sale of the bonds are not taxable to the utility. If this assumption
proves to be incorrect, the benefits associated with securitization would
not be realized. The Company anticipates that this issue will be resolved
in the near future as the securitization mechanism is implemented in other
states. In the event this issue is resolved adversely, the manner of
transition cost recovery would have to be reconsidered.
(5)It should be noted that, at this time, Consumers Energy does not
propose to securitize any amounts related to employee restructuring or
other implementation costs.
-18-
Table 3--(All figures in $ million)
Additional Amounts
Transition For Customer Total Amount
Costs Rate Reduction To Be Securitized
(A) Nuclear facilities $ 70.3 $ 241.3 $ 311.6
(B) Generation-related 220.1 332.4 552.5
regulatory assets
(C) Ludington/hydro 16.2 8.0 24.2
decommissioning
(D) Contract capacity 1,459.5 1,735.4 3,194.9
costs associated
with NUG
agreements
(E) Transition costs (4.9) (.5) (5.4)
recovered via
Rate DA regulatory
charges approved
by MPSC
_________ _________ _________
Total $1,761.2 $2,316.6 $4,077.8
The revenue requirement associated with the items listed in
Table 3 would be removed from the utility's existing rates, and would be
replaced with a securitization charge. For purposes of calculating the
expected customer benefits from securitization, Consumers Energy has
assumed that the bonds issued have a term of 15 years, an interest rate of
7.4%, and that the amounts collected by the utility for bond debt service
are not taxable for Michigan Single Business Tax purposes. Using these
assumptions, the resulting securitization charge is 1.12 cents per kWh.
When the implementation charge (employee-related restructuring and other
implementation costs) of 0.14 cents per kWh is added, the total
restructuring charge under this approach is 1.26 cents per kWh. See
Attachment 1 for details of this calculation. As noted previously, it
would be essential to periodically "true-up" the collection of these
amounts to reflect actual sales levels.
The customer savings expected from this approach are
substantial. As set forth below in Section III in greater detail,
securitization provides an immediate savings to customers in excess of
$200 million relative to rates that would otherwise be in effect in the
absence of securitization. See Section III.
The issuance of the securitization bonds would generate
substantial funds which would be utilized over a reasonable period of
time, consistent with prudent financial management considerations, in the
following manner:
(A) The proceeds from the securitization of nuclear facilities
and regulatory assets would be used to reduce Consumers Energy's debt
and equity in a proportion similar to that reflected in its current
capital structure.
(B) The proceeds from the securitization of the present value
of the contract capacity charges would be handled as follows:
-- The funds would be deposited in a third party managed
investment trust fund
-- Any earnings of the investment trust in excess of the
amount needed to satisfy the approved amounts payable to the PPA
suppliers will be distributed to customers. A reasonable
estimate of this excess earnings amount ranges from $75 million
to $150 million.
-- Any remaining balance in the investment trust fund at
2007 would also be distributed to customers.
-- Buyouts, buydowns, financial restructuring or
renegotiation of NUG power purchase agreements would be funded
from the investment trust subject to the consent of the trustee.
-20-
Table 4
Summary of Transition Costs, Securitization Amounts, and Surcharges
(million)
Item
Without With
Securitization Securitization
1. Generation-related $ 70.3 $ 311.6
regulatory assets
2. Nuclear capital costs 220.1 552.5
3. Ludington/hydro 16.2 24.2
decommissioning
4. Power purchase agreement 1,459.5 3,194.9
costs
5. Rate DA charge offset (4.9) (5.4)
_________ _________
6. Total $1,761.2 $ 4077.8
7. Transition Charge 1.31 cents per kWh
8. Securitization Charge 1.12 cents per kWh
9. Employee-related costs $ 50.0 $ 50.0
10. Other implementation $ 150.0 $ 150.0
costs
11. Total implementation 0.14 cents per kWh 0.14 cents per kWh
charge
12. Total charge 1.45 cents per kWh 1.26 cents per kWh
-21-
Question 3: A description of how the utility would allocate
direct access capacity, including procedures for
bidding and aggregation. The utility should also
indicate any appropriate alternatives to the
phase-in schedule.
A. Allocation
To ensure that all customers have an opportunity to participate
in retail direct access, Consumers Energy would first determine the blocks
of direct access capacity available to residential, secondary and primary
customer class based upon the percentage of annual energy consumption for
each class. This would result in the residential, secondary and primary
customer classes being allocated 49,000 kW, 32,000 kW and 69,000 kW of
each 150 MW block of direct access capacity, respectively. Bidding
procedures would then be followed within each customer class to allocate
the available capacity to individual customers (or aggregators). The
following table sets forth how Consumers Energy would phase in the retail
direct access program:
Table 5
RETAIL DIRECT ACCESS SCHEDULE
(All figures in kW of Demand)
RESIDENTIAL SECONDARY PRIMARY
7/97 49,000 32,000 69,000
1/98 98,000 64,000 138,000
1/99 147,000 96,000 207,000
1/2000 196,000 128,000 276,000
1/01 245,000 160,000 No Limits
1/02 294,000 192,000 No Limits
1/03 343,000* 224,000 No Limits
1/04 No Limits No Limits No Limits
* Based upon an average demand of 4 kW per residential
customer, This equates to approximately 85,750
customers.
-22-
B. Bidding
To initiate the bidding procedure, the Company would conduct an
auction three months prior to commencement of service. A participant in
the auction process would submit a sealed bid indicating the number of 200
kW blocks of available retail access capacity allowances within each class
it desires to purchase, and the amount it is willing to pay for each such
200 kW block. The highest bidders per block of capacity will be given
first priority to that block. To ensure an adequate number of
participants in the program, no single bidder would be awarded more than
10,000 kW from each of the three classes (i.e., primary, secondary and
residential). The bid amounts would be in addition to all other
applicable charges, and would be payable within thirty days. All fees
collected would be credited to the recovery of other restructuring
implementation costs previously discussed in response to Question 1.
Successful bidders would be able to sell or otherwise transfer their
allowances to other eligible parties.
C. Aggregation
All customers with annual maximum demands of less than 1,000 kW
and whose usage is not measured with demand recording meters would be
required to procure their power through an aggregator. The aggregator
could be any entity, such as a marketer, broker, customer, or distribution
utility, which is certificated by the Michigan Public Service
Commission.(6) The certification process would ensure that aggregators
have the ability to meet their obligations. During the phase-in period,
the aggregator will be able to solicit customers via the bidding process.
Aggregators would be required to contract for a minimum level of
1,000 kW but could not exceed the quantity of load allowances secured in
the bidding process. Aggregators may increase the amount of load they
serve in subsequent bid proceedings by successfully bidding for additional
allowances, or acquiring additional allowances from other parties
participating in the program. Aggregators would be required to
independently schedule deliveries to each customer class of retail direct
access customer (residential, secondary, and primary).
D. Alternatives to the Phase-In Schedule
The Commission noted in a footnote in the February 5 Order
(p. 3) that the Michigan Electric Cooperative Association had claimed that
the 2.5% blocks of capacity may not be feasible for some small utilities.
Consumer Energy believes that some flexibility to address unusual
situations of very small utilities may be appropriate, provided that the
January 1, 2001 and January 1, 2004 dates for full retail direct access
are not extended, and provided that the reciprocity condition is in force.
That is, to the extent that a small utility wishes to sell to a customer
located in another utility's service territory, no claims of special
circumstances on its own system should serve to delay open access.
- ---------------------
(6)Legislation would be appropriate to establish the certification
requirements which would be administered by the Commission.
-24-
Question 4: Tariff sheets for direct access service, with
supporting workpapers and applicable FERC
tariffs.
Attachment 4 to this Response is a set of tariffs that could be
used to initiate the retail direct access program in 1997. While they are
largely self-explanatory, there are several points deserving special
comment:
(1) The rates and charges included in the tariffs assume the
approval by this Commission and by the Federal Energy Regulatory
Commission of the appropriate classification of transmission and
distribution facilities in the manner set forth in Consumers Energy's
application in Case No. U-11283. The Company notes that, on February
28, 1997, the Commission issued an order setting that matter for
hearing.
(2) The cost of supplying electricity can fluctuate
dramatically over the course of a year, month, and day. The price at
which a supplier is willing to sell power could be significantly
different at midnight on an April evening than it will be at 3 PM in
the afternoon of a 100 degree day in July. Current metering and
billing techniques, coupled with standard ratemaking practices,
results in most customers being billed on an average rate basis. The
meter on a house or place of business records only the total amount
of kWh consumed, and not the time of use. Customers are therefore
largely indifferent to time of use pricing considerations because
they pay the same unit price 24 hours a day, 365 days a year. The
implementation of any meaningful retail direct access program,
however, is ultimately dependent upon the availability to the
customer, the generation supplier and the transmission/distribution
utility of instantaneous or real time usage and generation supply
information. The metering and communications technology necessary to
provide such real time information is not presently in place for the
vast majority of utility customers, and it is a formidable task to
undertake the installation of the required technology for 1.4 million
customers. Attachment 3 describes Consumers Energy's plan for the
installation of the necessary technology. In order to allow for the
immediate phase-in of retail direct access for all customer classes,
however, Consumers Energy has developed an interim "approximation"
program that would utilize real time information from a statistically
significant sample of customers. This program assumes that customers
electing retail direct access, but not yet equipped with the
necessary metering technology would have load patterns consistent
with this sample. Please refer to Attachment 4, Rule F5.4.(7) The
reliance on sampling techniques would be reduced and hopefully
eliminated by the year 2004 by the phased installation of new
technology for all customers. Of course, Aggregators or individual
customers who do not wish to be billed based upon the load pattern
sampling technique during the phase-in period may pay to have the
appropriate metering and communications technology installed earlier.
(3) The rates and charges in Attachment 4 are based upon the
transmission and utilization principles imposed by FERC. Certain of
these principles, however, do not easily translate from the wholesale
environment to the retail environment. For example, FERC pricing for
transmission reservation is based on each customer's utilization of
the transmission system during the one system peak hour of the month.
Over 1.4 million of Consumers Energy's customers are not equipped
with the type of metering necessary to determine system utilization
at any single point in time. Thus, FERC pricing practices cannot be
directly applied. Another example of this situation is that the FERC
OATT tariff contains a $3,035 monthly customer charge. Direct
assessment of such a charge in a retail direct access transaction
would obviously adversely affect the economics of many such
transactions. These items are merely examples of the types of issues
which arise as the FERC tariff is used as the basis for retail direct
access transactions. In the attached tariffs, the Company has
attempted to capture as many of the FERC pricing policies and
practices as is reasonably possible, while still recognizing the
differences between wholesale service and retail service.
(4) As the Commission is aware, FERC has directed that rates,
terms and conditions of service for a retail direct access program
would also be filed with the FERC for its review and approval.
Consumers Energy will comply.
- ---------------------
(7)Consumers Energy notes its belief that it is important that all
utilities should offer a comparable program, rather than one more
restrictive.
-26-
Question 5: A description, including tariff sheets, for the
standby service that the utility would provide to
direct access customers.
The direct access service tariff sheets discussed above in
Response to Question 4 include a new Standby Service Tariff for use by
retail direct access customers. See Attachment 4. This incorporates the
provisions on length and availability of service recommended in the MPSC
Staff Report. It must be noted that standby service will, from the outset
of retail direct access, be available from sources other than Consumers
Energy. Thus, customers will be free to choose from multiple sources of
standby service.
In order to assure a minimum available supply of standby service
for an initial two year period, however, as well as a predictable price
for that service during that time, Consumers Energy has accepted the
Staff's recommendation that the utility should provide a regulated standby
service for that period, but not beyond December 31, 2000. As the Staff
explained, this will provide an opportunity for the standby generation
market to further develop, and for parties to construct additional standby
generating capacity. Consumers Energy has set the cost of the proposed
standby service based upon the approximate cost of a new green field gas-
fired peaking generator.
The Company also proposes to close the existing standby tariff
provisions, Rule D-7, Rate B-1 and Rate CG, to new standby business as
part of these proceedings. Existing customers receiving standby service
on these rates would be allowed to continue on these rates until
January 1, 2001 at which time they can purchase standby service from
sources other than the Company or from the Company at market-based rates.
Commencing January 1, 2001, standby service will be provided to all
customers at market-based rates.
-27-
Question 6: A list of any new or additional charges that the
utility does not currently assess that would be
imposed under a direct access program.
The implementation of a retail direct access program in which
all classes of customers are eligible to purchase generation from
alternative suppliers is a dramatic change in the traditional relationship
between utilities and electricity customers. This change will undoubtedly
cause many changes in the types of services offered and charges collected
by the utility, many of which cannot currently be specifically identified.
Consumers Energy believes that there will likely be a continually changing
menu of services offered by distribution utilities and other entities,
depending upon what the market expects and is willing to pay for. As a
general rule, services which are offered by multiple providers should be
priced in accordance with the market demand for those services.
Examples of additional services arising from the implementation
of direct access are: (i) billing services to third parties; (ii)
supplier switching services; (iii) credit and collection services
provided for third parties; (iv) third party performance bonds or
deposits. Undoubtedly additional examples will arise over time.
Revisions to certain utility practices and charges will also
clearly be necessary as part of the transition to a restructured industry.
Some examples of such revisions are the following:
(A) Customer contribution requirements--Since many customers
will no longer purchase generation services from the distribution
utility, the level of investment the utility is willing to make to
extend service to new customers without an offsetting contribution
from the customer will change.
(B) Bill payment schedules--The unbundling of utility charges
and the inclusion of third party charges on bills may necessitate
changes in payment schedules and associated charges.
(C) Late payment and non-payment practices--Inclusion of third
party charges on bills will also require changes in late payment/non-
payment practices and charges.
(D) Miscellaneous billing practices--Additional changes to
existing billing practice rules will undoubtedly be necessary.
Consumers Energy continues to examine these issues.
-29-
Question 7: A description of any transmission constraints or
limitations on the ability to import power into
the utility's system. This description should
include: (a) the amount of electricity currently
being imported into the system from Michigan
sources and from outside the state; (b) the
nature of the existing imports, e.g., wholesale
transactions; (c) the nature and location of the
constraints; (d) an estimate of the amount of
direct access electricity that could be imported
into the utility's system given existing
constraints; and (e) methods of removing
constraints and their estimated costs and
effects.
A detailed discussion of the matters raised in Question 7 is
contained in Attachment 5. As evidenced by both the Staff discussion of
transmission issues and Consumers Energy's detailed answers, the issue of
transmission constraints and interconnection capacity is highly complex.
It is critical that the issues be both understood and resolved if Michigan
is to advance to a competitive electric industry without causing a
negative impact on the reliability of today's system. Transmission
capacity and interconnection capacity are also critical to assuring a
robust power supply market which is not subject to delivery constraints.
Michigan's unique geography is only partially responsible for
the difficulties in assessing the availability of transmission capacity.
The physical properties of electricity bear the brunt of the
responsibility. The following is a summary of simplified concepts
important to understanding the issues raised in question 7.
1. Transmission is affected by what generators are on line, at
what capacity, and where the load is located.
2. Importing electricity at more than one interconnection at
the same time affects the transmission system differently than
importation at only one interconnection point.
3. The elimination of transmission constraints at one point
does not necessarily eliminate transmission problems as a whole, and
it may create constraints at other points.
4. There is sufficient ATC in the near term (through 2000) to
accommodate the phase-in of retail access in Michigan. Long term
solutions will require additional transformers, extra capacitors, new
substations, and/or new interconnections in Michigan, Indiana, Ohio
and/or Ontario. These possible projects are also detailed in
Attachment 5.
5. Additional generation located within Michigan or the
designation of certain generating facilities as "must run" units
could also be part of the solution for the future.
6. The Staff Report recommends that Consumers Energy and
Detroit Edison be required to provide standby (if requested by the
customer) at regulated rates for two years for any customer, but not
beyond December 31, 2000. Consumers Energy supports this
recommendation since it effectively eliminates concerns about
transmission constraint issues for the near term.
7. As discussed further in response to Question # 8, Consumers
Energy supports the development of an independent system operator.
If properly structured, an ISO will assure that the transmission
system is utilized to its fullest capacity on a fair and open access
basis.
8. Consumers Energy will make good faith efforts to upgrade
its transmission system when required to alleviate transmission
constraints, providing that recovery of such expenditures is assured
in addition to the CPI-1% adjustment mechanism which applies to
energy delivery services.
Consumers Energy recommends that transmission issues be
recognized as issues that should be dealt with throughout the transition
period. The resolution of transmission issues on a long term basis must
be intertwined with the resolution of ISO/market exchange and market power
issues.
-31-
Question 8: The status of any ongoing discussions regarding
the development of an Independent System
Operator.
Transmission related issues encompass not only reliability
issues, but also issues related to the provision of open access by a
transmission owner, when that owner is a vertically integrated utility.
Consumers Energy believes that an Independent System Operator ("ISO") can
help resolve both types of problems.
There is no universal definition of an independent system
operator. This can readily be demonstrated by a comparison of the various
ISO proposals around the country. The Midwest ISO under discussion does
not include generation control responsibilities. The proposed
Pennsylvania-New Jersey-Maryland ("PJM") ISO contemplates the management
of a competitive energy market, whereas the proposed California ISO will
be separate from a power exchange. The Texas ISO will assist control
areas with coordination, whereas the PJM ISO and the California ISO will
operate a single control area. Some ISOs will simply coordinate operating
schedules provided by individual load-serving entities, while others will
perform the schedule and dispatch of generation for their members. The
actual functions of an ISO are up to each ISO to determine, providing the
ISO meets the 11 basic principles set forth by FERC which were described
in the Staff Report.
Consumers Energy is concerned about the ability of transmission
managers to maintain the reliability of the system in light of the rapidly
increasing types and amounts of power transfers that will be taking place
in the future. Today's transmission system was not designed for the
functions it will be asked to perform in a retail access environment.
This problem has become a serious concern for the North American Electric
Reliability Council ("NERC"). NERC is responsible for establishing the
operating and planning standards necessary for the electric utility
industry to maintain the reliability of the power system at its current
high level. Specific NERC activities currently underway are detailed in
Attachment 6.
In light of direction from FERC in Order 888 to revise the
existing Michigan Electric Power Coordinating Center ("MEPCC"), Consumers
Energy and Detroit Edison undertook a series of discussions which
included, among other things, the possible expansion of the MEPCC to a
Michigan ISO. The advantages of a Michigan ISO would be the ability to
utilize the capabilities of the current MEPCC for Consumers Energy-Detroit
Edison transmission business functions, generation control and power
security monitoring. Because these functions are performed by the MEPCC
today, the time required to implement a Michigan ISO would be much shorter
than that required for a regional ISO. If these discussions are resumed,
Consumers recommends that the MPSC Electric Staff play a role in the
formulation of a statewide ISO.
Because of the broad interest in a regional ISO, Consumers
Energy has joined the initiative to form a Midwest ISO. There are
currently 24 members of the Midwest ISO. See Attachment 7. While there
is much work to be done on the Midwest ISO, there is general consensus on
several key elements, including operations, planning and dispute
resolution.
The Midwest ISO would assume responsibility for all transmission
service business currently being conducted by Consumers Energy ( and other
transmission owners). The membership would "buy" all of its transmission
service from the ISO. The revenues obtained for this service would be
allocated back to the transmission owners. The responsibility for system
reliability would also be transferred from Consumers Energy to the ISO.
Control area functions such as automatic generation control and
transaction schedule implementation would not be performed by the ISO, and
would be functions retained by the utility. A dispute resolution
procedure along the lines of that proposed for the ECAR Regional
Transmission Group is a part of the current version of the Midwest ISO
Operating Agreement being considered.
The proposed governance of the Midwest ISO is still under
discussion. Current plans call for a 12 member board with three
representatives from transmission owners. Non-owners would elect the
remaining nine representatives. No more than two members may represent an
identifiable market participant groups. There is ongoing debate about the
necessary procedures to change the Operating Agreement.
The major unresolved issue is transmission pricing. There are
several different proposals under discussion ranging from zonal pricing
(priced at the embedded cost in the buyer's zone) to a single ISO-wide
rate set at the average cost of all transmission in the system. Various
task forces within the ISO are trying to merge the proposals into one
proposal acceptable to all members.
Because Michigan is physically located at a geographic extreme
of the ISO, pricing is extremely important to Consumers Energy. In all
likelihood, the ability or inability to agree on a pricing methodology
will be the deciding factor in whether or not the Midwest ISO becomes a
reality.
To date, the Midwest ISO is comprised only of transmission
owners. In addition to Consumers Energy, Detroit Edison, AEP/Michigan and
the Michigan Public Power Agency are also members from Michigan. The
Midwest ISO continues to have ongoing meetings with various stakeholders,
including customers, marketers, brokers and regulators from the affected
states. Provided that the Midwest ISO can resolve outstanding issues, an
application must be filed, and approved by the FERC. The most optimistic
estimate is that the Midwest ISO could be operational in 2000.
-34-
Question 9: A description of the methods that the utility
would propose to alleviate concerns regarding
market power in a competitive market.
Although the question appears to assume that utilities operating
in Michigan will have market power in an open access environment,
Consumers Energy cautions the Commission against prematurely jumping to
that conclusion. As is evident from proceedings which have been held at
the FERC on the subject of market power, it can be a fairly complex
subject. As will be discussed below, however, Consumers Energy believes a
conclusion can be drawn at this time that, given (i) the phase-in schedule
set forth in the Staff Report, (ii) the availability of power import
capability, (iii) the assurance of a regulated standby service, and (iv)
the number of potential power suppliers, market power is clearly not a
problem for at least the initial several years of the retail access
program under discussion. Additional analyses may prove to be necessary
in the future to determine the extent to which market power will be a
legitimate concern.
It should first be noted that concerns about market power being
possessed by Michigan electric utilities should be largely alleviated by
the fact that, under the Staff plan, the utility will retain the
obligation to provide generation service at frozen rates through
December 31, 2000 for primary customers, and through December 31, 2003 for
secondary customers. See Section III of this Response. Thus, since no
customer will be required to make market-based purchases of generation
prior to those dates, and all customers may, if they wish, continue
receiving generation service from the local utility at prescribed prices,
customers are protected from the exercise of market power, assuming,
arguendo, that some market participants may possess it.
As discussed in response to question 7 regarding transmission
constraints, there is not currently an unlimited amount of import
capability into Michigan or into Consumers Energy's service territory.
Notwithstanding the existing limitations, however, this situation does not
give rise to any material market power concerns because of the retail
access phase-in schedule contained in the Staff Report. Relative to the
amount of import capability that does currently exist, the amount of
customer load eligible for retail access in 1997-2000 is not sufficient to
create any market power concerns. For Consumers Energy, the amount of
customer load eligible for retail access is approximately 150 MW in 1997,
300 MW in 1998, 450 MW in 1999, and 600 MW in the year 2000. These
amounts of customer load that will be able to "shop" for power should be
compared to over 2000 MW of on-peak transmission capacity which is
available to bring power into Consumers Energy's service territory. Thus,
the relative amounts of import capability and customer load shopping for
generation suppliers indicates no material market power problem can exist.
With respect to the limited periods during the year when
transmission constraints may exist, market power concerns are nevertheless
alleviated by the regulated standby obligation recommended in the Staff
Report. That is, the Staff recommends, and Consumers Energy has accepted,
a requirement that the host utility provide a standby generation service
for the first two years of the retail access program. Since this standby
service will be available at a regulated rate, any limitations on import
capability which might exist are resolved. This two year period provides
an adequate opportunity for the generation market to further develop, for
additional transmission capability to be developed, and for additional in-
state generation capacity to be brought into or returned to service.
Finally, the number of potential power suppliers which could
sell to customers in Michigan provides adequate assurance that market
power could not be exercised by individual market participants. There are
numerous potential suppliers of generation services already present in
Michigan, including generation owned by retail customers. Over 30
customers just in Consumers Energy's service territory own varying amounts
of generating capacity. In addition, customers having the ability to
choose power suppliers will be able to reach well beyond the Consumers
Energy service territory and the existing MECS control area. This wide
market area is the result of a strong extra high voltage transmission
network that can physically reach generation sources anywhere in the
eastern interconnection. Thus, direct access customers will have a wide
number of power suppliers available to them, resulting in a very
competitive power market environment.
As evidence of this capability, Consumers Energy has, over the
years, actively purchased power from not only first tier utilities (i.e.,
companies with whom Consumers Energy is directly interconnected), but also
from second tier utilities (i.e., companies with whom Consumers Energy is
one system removed). These include CINergy, Ontario Hydro, Centerior,
Central Illinois Public Service, Louisville Gas and Electric, and
Commonwealth Edison. This past experience gives an indication that, under
most conditions, the market available to direct access customers is quite
broad and diverse.
Notwithstanding transmission constraints which may have existed
at system peak conditions in the past, system operators have been able to
maintain customer service reliability. As the industry is restructured,
customers will have options available to them to maintain their desired
level of service reliability, even at times when transmission constraints
may limit power supply alternatives. It will be important, however, for
customers, (or their aggregators or other representatives), to accept
responsibility for transactions that were previously handled by the local
utility. As discussed in the September 1995 NERC Report, Reliability
Assessment, 1995-2004, customers who choose to be supplied from other
than their local supplier will need to become more knowledgeable about
power supplies and transmission systems, including overall supply
reliability, services and information that were previously bundled in
their local provider's electricity rates. The NERC report states:
"In the new competitive environment:
1. Buyers must assess for themselves the reliability
or 'firmness' of electricity services purchased
from competing suppliers by evaluating the
validity of their claims."
Direct access customers will need to assure their own power supply and
transmission service reliability through the contracts they sign with
power suppliers and transmission providers.
Additional Methods of Mitigating Market Power
As explained above, Consumers Energy does not believe that, in
the initial years of the retail access program envisioned by the Staff,
market power is a material concern. While the situation that will exist
beyond that time is dependent upon many different factors, the following
are some of the options that suppliers, transmission providers and
customers will have available to mitigate future concerns regarding market
power in a competitive environment.
A. Transmission Expansion -- While transmission limitations
may limit the size of the power market in which customers can effectively
shop for firm power, FERC Order No. 888 requires transmission providers to
expand or upgrade their transmission systems to accommodate service
requests, assuming that the requester is willing to compensate the
provider for upgrade costs. Thus, customers and transmission providers can
effectively increase the size of the market through the expansion and
maintenance of reasonable and cost effective transmission capability.
Consumers Energy will continue to plan and operate its transmission
network for the benefit of all customer classes. It will make every effort
to offer cost effective expansion and upgrade alternatives when requested,
and will actively pursue implementation of necessary upgrades.
B. Independent System Operator ("ISO") -- FERC stated in the
Open Access Rule that the creation of organizations such as ISO's will
assist in the mitigation of market power. To this end, Consumers Energy is
participating in the Midwest ISO discussions. See response to Question 8
above. These discussions, which have 24 participants in the ECAR and MAIN
regions of NERC, may lead to an independently managed and operated
regional transmission system that complies with FERC's ISO principles.
Consumers Energy will provide non-discriminatory, comparable transmission
service to all customers, and will continue to pursue a regional or state
ISO, or some similar organization that meets FERC's ISO principles, as an
appropriate means of achieving non-discriminatory, comparable transmission
service to all customers.
C. Interruptible and Direct Controlled Load Management -- An
option available to direct access customers to manage the potential impact
of power supply interruptions or transmission congestion, or as an
alternative to back-up or stand-by service, is for the customer to install
equipment to lower energy use when their primary and/or back-up power
supply is not available. Such devices can be a cost effective alternative
for certain customers. Interruptible and direct controlled load management
services are already available to customers who want them. Indeed,
Consumers Energy expects that it and others will offer such services, as
the market for them develops. Many vendors exist who will work with
customers in developing individual load control programs.
D. Michigan Power Exchange -- The creation of an independent
power exchange where direct access customers could purchase power, could
provide a medium for matching energy users and energy suppliers, thereby
further mitigating any perceived market power. Such a power exchange would
provide yet another supply option for customers. Consumers Energy expects
that such exchanges will develop in a competitive environment.
E. Non-utility Developers -- As noted in the Staff Report,
multiple power suppliers can enter into the market relatively easily and
the resulting competition will work to assure reasonable prices and
adequate supplies for customers. Certainly the activity of non-utility
developers in Michigan over the past 10 years supports this conclusion.
The active involvement of non-utility developers in Michigan has
demonstrated that these suppliers are a viable alternative for future
power supplies.
F. Self-generation Option -- Large customers have the option
of constructing their own generating facility, either for partial service
or full service of their load. A number of customers have found this to be
cost effective, particularly when they can take advantage of co-generation
in a manufacturing process having significant process steam demands. This
ability to install self-generation clearly mitigates any market power
which might be possessed by other generation providers in Michigan.
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III. SUMMARY OF ESSENTIAL FEATURES OF RESTRUCTURING PLAN
So that there is no doubt about the restructuring plan that
Consumers Energy believes the Commission should endorse, this section of
this Response sets forth, in summary fashion, the essential elements of
the plan the Company is willing to voluntarily implement. This discussion
includes a description of certain elements of the restructuring plan that
were identified in the Staff Report but were not addressed in the
preceding sections.
A. Retail Direct Access Schedule
Retail direct access would be phased-in for Consumers Energy on
the following schedule:
RETAIL DIRECT ACCESS SCHEDULE
(All figures in kW of Demand)
RESIDENTIAL SECONDARY PRIMARY
7/97 49,000 32,000 69,000
1/98 98,000 64,000 138,000
1/99 147,000 96,000 207,000
1/2000 196,000 128,000 276,000
1/01 245,000 160,000 No Limits
1/02 294,000 192,000 No Limits
1/03 343,000* 224,000 No Limits
1/04 No Limits No Limits No Limits
* Based upon an average demand of 4 kW per residential
customer, This equates to approximately 85,750
customers.
Retail direct access for other Michigan utilities would be
phased in on a comparable schedule, as described in the Staff Report.
B. Allocation and Bidding
The available retail direct access load would be made available
to customer classes and individual customers as described previously in
this Response. In summary, the capacity would be distributed among
primary customers, secondary customers and residential customers based
upon the current ratio of class usage to total system usage. Bidding
programs would then be conducted to allocate the available capacity among
individual customers and aggregators.
C. Transition Cost Recovery
Consistent with the Staff's recommendations, the Commission
should conclude that Consumers Energy's transition costs are as set forth
in the Response to Question 1. This approach permits recovery of the
generation-related portion of regulatory assets, the net book value of
nuclear facilities, Ludington/hydro decommissioning costs, and a portion
of the contract charges associated with purchases from non-utility
generators. As explained above, this approach results in a 1.31 cents per
kWh transition charge, which would only be applicable to those customers
electing retail direct access, and only for the 1997-2007 time period. To
the extent the securitization option is available in the manner described
above, the revenue requirement associated with the securitized assets
would be removed from the Company's bundled rates, and a securitization
charge of 1.12 cents per kWh would be applicable to all customers for the
15 year term of the securitization bonds.
The Commission should also find that the recovery of costs
associated with the implementation of industry restructuring should be
accomplished in the manner described above in response to Questions 1 and
2. Thus, the costs of employee-related restructuring activities, revised
metering and billing systems and equipment, and the associated
infrastructure, and implementation of an independent system operator
should also be recovered from customers as part of transition costs.
Based upon the best information available at this time, Consumers Energy
estimates that these costs will add 0.14 cents per kWh to both the
transition charge and the securitization charge indicated above.
D. Rates, Terms and Conditions of Retail Direct Access
Service
Rates, terms and conditions for retail direct access service,
including standby service for direct access customers, and reflecting the
assumptions made herein, are set forth in Attachment 4. Recognition of
the jurisdictional role claimed by the FERC is necessary in connection
with these tariffs.
E. Rate Freeze
The Staff Report indicates that the implementation of retail
direct access should be accompanied by a freeze on base electric rates
(i.e., the non-PSCR component of rates), subject to certain exceptions.
This freeze would be effective until January 1, 2001 for commercial and
industrial customers taking service at primary voltage levels (the date on
which such customers are all eligible for retail direct access), and until
January 1, 2004 for all other customers (when all other customers are
eligible for retail direct access).
The Staff also indicated that certain exceptions to this freeze
would be appropriate. Consumers Energy believes that these should include
the following: (a) increases resulting from the operation of the
performance-based rate mechanism for transmission and distribution rates
(see below); (b) increases resulting from changes in accounting
requirements, state or federal laws or regulations which affect the cost
of providing service by at least $2 million annually; (c) increases
resulting from transmission system upgrades or expansions required to
alleviate transmission constraints; (d) changes in projected nuclear
decommissioning costs; and (e) miscellaneous changes in rules and non-
price related rate provisions such as extension policies, billing
practices, late payment provisions, and other such policies.
F. PSCR Suspension
The Staff report also indicates that the power supply cost
recovery ("PSCR") clause should be suspended during the transition period
(and ultimately eliminated entirely). This recommendation should be
implemented for Consumers Energy by adjusting for the levelized phased-in
capacity charge increases for NUG purchases which have previously been
approved by the Commission, and an adjustment to reflect the normalization
of generating plant outage schedules. In addition, there are two PSCR
reconciliation cases pending at the Commission for Consumers Energy for
1994 and 1995, which reflect under-recoveries of $15.3 million and $13.7
million, respectively. In addition, the 1996 reconciliation and the
projected 1997 reconciliation amounts should also be reflected.
The impact of these PSCR-related items is to increase customers
rates by 0.32 cents per kWh. The system average rate would increase from
7.02 cents per kWh to 7.34 cents per kWh. See Attachment 8. It should
be noted that this calculation does not reflect the significant impact a
dissolution of the Michigan Electric Coordinated Systems ("MECS")
arrangement between Consumers Energy and Detroit Edison could have on PSCR
costs. Therefore, a further adjustment may also be necessary for this
reason.(8)
If the securitization approach becomes an available option in
the manner described previously in this Response, this PSCR-related
increase could be more than offset by the benefits associated with
securitization. The immediate annual customer savings associated with
securitization are approximately $226 million, as shown on Attachment 8.
This reflects a reduction in the 7.34 cents per kWh average rate to 6.68
cents per kWh, or approximately a 9% rate reduction. Consumers Energy
believes these savings should be used first to correct cross-subsidization
issues within and between customer rate classes, with any remaining amount
spread to all customer classes.
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(8)A dispute between the two companies concerning the future of MECS
is currently under review by the FERC. FERC Docket Nos. OA97-258-000 and
ER97-1168-000, and OA97-472-000 and ER97-1023-000. Detroit Edison is
seeking dissolution of MECS, effective as early as April 30, 1997.
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G. Performance-Based Ratemaking Mechanism
The Staff Report contains an excellent discussion of a
performance-based approach to the regulation of transmission and
distribution services. Because of the importance of maintaining reliable,
high quality service, it will clearly be necessary to make substantial
expenditures to continue to operate and maintain the Company's
transmission and distribution system. The indexing approach recommended
in the Staff Report recognizes that such expenditures will be necessary
and that it would be desirable to develop non-traditional incentives which
will encourage the utility to deliver high quality service at a reasonable
cost.
As part of its endorsement of the Staff Report, the Commission
should explicitly approve performance-based ratemaking proposals which:
(a) apply to non-generation rates, (b) provide adequate incentives for the
maintenance of transmission/distribution service quality and reliability,
and (c) provide for annual increases in non-generation rates which do not
exceed the percentage increase in the Consumers Price Index ("CPI"), less
one percent.
H. Obligation To Serve
The restructuring of the electric industry requires that the
electric utility's obligation to provide service be substantially
redefined. The Commission should adopt the following principles:
(1) Except as otherwise stated below, the generation of
electricity will no longer be regulated as a public utility function
or service. The provision of electric generation service will be a
matter of contract between a retail customer and a generation
supplier (or aggregator).
(2) A company supplying transmission and distribution services
will, subject to technical and operational constraints, have an
obligation to provide transmission and
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distribution services to all retail customers within its service territory
at rates and on terms and conditions authorized by the appropriate
regulatory authority.(9)
(3) Through December 31, 2000 for retail customers served at
primary voltage levels, and through December 31, 2003 for retail
customers served at secondary voltage levels, existing electric
public utilities will have the obligation to provide generation
service.
(4) After the dates stated in paragraph 3, a company supplying
transmission and distribution services will have the obligation to
procure generation services, to the extent sufficient generation
supplies are available, for retail customers who fail to make
alternative arrangements for generation service and who request the
company to procure such generation supply. This obligation does not,
however, require the company to build generating capacity or to enter
into long term power purchase agreements. The pricing for such
service will be market-based (i.e., current market price plus an
appropriate adder).
(5) Through December 31, 2000, a company supplying transmission
and distribution services will have an obligation to provide standby
generation service to retail direct access customers. As of
January 1, 2001, this obligation is terminated, and the provision of
standby service will be a matter of contract between a retail
customer and a generation supplier.
I. Reciprocity
Reciprocity is another critical element of the Staff
restructuring plan. Without strong reciprocity requirements, there can be
no fair, competitive generation market, and, as noted previously,
stranded/transition costs would be dramatically increased. Because the
arguments in favor of reciprocity have been put before the Commission in
other proceedings, Consumers Energy will not repeat those arguments in
this Response. The Commission should, however, endorse the following
principles:
(1) No electric utility operating in Michigan should be
permitted to utilize the transmission and distribution system of
another Michigan utility to make retail sales unless the utility
wishing to make the sale provides comparable direct access to retail
customers located within its service territory.
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(9)To the extent transmission system expansions or upgrades are
necessary, prompt and reasonable rate recognition of the associated
investment is critical.
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(2) No generation supplier that also provides retail
distribution services, or that has an affiliate that provides retail
distribution services, should be permitted to utilize the
transmission and distribution system of a Michigan utility to make
retail sales unless the supplier or its affiliate provides a
comparable retail direct access service. If the transaction involves
an intermediary (such as a marketer or broker), the reciprocity
obligation could be satisfied by either the regional
transmission/distribution affiliate of the intermediary, or by the
owner of the generation source or its regional
transmission/distribution affiliate.
(3) A "comparable" retail direct access service is one which
(i) provides for retail direct access in an amount of retail customer
load which is equivalent to that provided by the transmission and
distribution company, (ii) specifies rates, terms and conditions that
are equivalent to those offered by the transmission and distribution
company, and that have been approved by all applicable regulatory
authorities for use in retail direct access transactions.
(4) "Sham" transactions should not be permitted to avoid the
reciprocity condition.
J. Creation of an Independent System Operator
Consumers Energy and other Michigan transmission-owning
utilities should proceed with the development of an ISO.
IV. CONCLUSION
As noted in Consumers Energy's January 21 Comments, the Company
believes that the industry restructuring framework set forth in the Staff
Report is a reasoned approach which is fair to all stakeholders. The
additional information provided in this Response should provide the
Commission with the necessary data to satisfy itself that the
recommendations contained in the Staff Report are indeed in the public
interest. Consumers Energy encourages the Commission to take the steps
necessary to allow these recommendations to be implemented.
Contrary to the apparent contentions of other parties(10),
Consumers Energy does not believe that throwing this process into further
hearings is likely to prove to be a satisfactory
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(10)See e.g., the Joint Request For Contested Case Hearings filed by
the Attorney General, ABATE and the Residential Ratepayer Consortium on
February 21, 1997.
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means of implementing industry restructuring. The Commission has properly
been proceeding thus far in a manner which allows all parties to comment
upon each aspect of the restructuring proposal, and to that end, has
already held public hearings and received written comments on the Staff
Report. Following the filing of this Response, the Commission has
scheduled additional public hearings and has provided an additional
opportunity for written comments on the information contained in this
Response. As of April 7, 1997 (when the written comments of other
interested persons are due), no one will be able to credibly complain that
they have not had a fair opportunity to express their views on the issues
raised by the Staff Report.
To allow this process to become bogged down in potentially
extraordinarily extended additional hearings at this time would, in the
opinion of Consumers Energy, be a significant mistake. It would make it
virtually impossible for the Commission to influence or be of any
assistance to the Legislature in 1997 as it begins its consideration of
utility restructuring. Indeed, during (and because of) the pendency of
the requested contested case hearings, the Commission's ability to
influence the public debate over utility restructuring at all would be
minimal. Commencing hearings would also postpone any possibility of
implementing any portion of the Staff plan in 1997, and probably for an
extended period thereafter. The Commission should be very reluctant to
initiate hearings that are sure to be lengthy, contentious, and in the
end, unlikely to produce materially different information than the
Commission already possesses.
As stated in the Introduction of this Response, Consumers Energy
believes that the Commission can and should take strong, productive action
in response to the information provided in this Response and by other
interested parties. Upon completing its analysis of the information it
has solicited, Consumers Energy believes the Commission should (i) issue
an order endorsing the restructuring plan set forth in the Staff Report,
as that plan has been further developed in this Response, (ii) include in
that order a recommendation to the Legislature that it enact legislation
which is consistent with that plan, and (iii) accept the Company's offer
of voluntary implementation.
Consumers Energy stands ready to proceed with the initial
implementation of the MPSC Staff restructuring plan, subject to the
Commission taking the steps outlined above, and subject to the Commission
approving the entirety of the implementation plan which is described in
this Response. In addition, because of the importance of gaining
legislative authorization of the restructuring plan, the Company's
willingness to voluntarily implement this plan would cease as of December
31, 1997, unless satisfactory utility restructuring legislation has been
enacted by that date. While there may well be alternative routes to
achieving utility industry restructuring besides what is described in the
Staff Report and in this Response, Consumers Energy doubts that there are
any that offer as great a likelihood of successful and expeditious
implementation.
Respectfully submitted,
CONSUMERS ENERGY COMPANY
Dated: March 7, 1997 By /s/ David W. Joos
----------------------------------
David W. Joos
Executive Vice President and
Chief Operating Officer - Electric
/s/ Jon Robinson
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David A. Mikelonis
Jon R. Robinson
212 West Michigan Avenue
Jackson, MI 49201
Attorneys for Consumers Energy
Company