19960424Staff Proposal B.pdf

STAFF PROPOSAL 1

STAFF'S PROPOSED AVOIDED COST METHODOLOGY
FOR PROJECTS LARGER THAN ONE MEGAWATT
CASE NO. IPC-E-95-9

Introduction

On January 31, 1995, the Idaho Public Utilities Commission issued Order Nos.
25882, 25883, and 25884 which required that utilities utilize their Integrated Resource
Plans (IRPs) to establish avoided cost rates for projects larger than one megawatt.
The Commission stated the following in its orders:

We believe that the adoption of the least cost planning methodology is
consistent with our goal of maintaining a regulatory climate that allows our
electric utilities to retain their advantageous posture in a marketplace that
is likely to become increasingly competitive. This will ultimately work to
the advantage of ratepayers in the form of rates lower than would
otherwise be in effect. By treating QFs [Qualifying Facilities] in the same
manner as utility acquired resources, we are further removing the shelter
that has been constructed around the QF industry. Requiring those
projects to prove their viability by market standards insures that utilities
will not be required to acquire resources priced higher than would result
from a least cost planning process. Ratepayers will not be
disadvantaged and QFs will be treated fairly and consistently with the
requirements and goals of PURPA.

See, e.g. Order No. 25884 at page 6.

In accordance with Order No. 22299, all utilities are required to prepare IRPs
biennially. The following elements are included in the development of the IRP:

1. Integrated evaluation of all resource options;
2. Least cost selection criterion for the resource plan;
3. Inclusion of environmental impacts and external costs of resources;
4. Analysis of planning uncertainties and risks; and
5. Public involvement in the planning process.

STAFF PROPOSAL 2

An IRP forms the basis for utility decisions regarding the timing, quantity, and
type of future resource acquisitions. The end result of integrated resource planning is
a set of resource options which represent the least cost means of meeting expected
future loads considering a reasonable range of planning uncertainties and risks. The
set of options with the highest probability of having the least cost, and which has an
acceptable level of risk, is usually referred to as the "base case" plan. The base case
plan is the starting point of the analytical process described in this document for
determining project-specific avoided cost rates for QF projects larger than 1 MW.

In the past, utilities have submitted IRPs to the Commission for filing, but no
formal process has been in place for detailed review or approval of the IRPs.
However, as a result of their increased utilization and importance as something other
than a planning document, utilities should expect their plans to be scrutinized more
carefully in the future. The Commission Staff intends to conduct thorough reviews of
the plans, and anticipates that hearings may be held to provide an opportunity to seek
comment. As in the past, utilities should not be bound to follow their IRP without
exception. In fact, when good cause is shown, they should be expected to deviate
from it. But absent good cause, they should now expect to be held to it more closely.
More importantly, the IRP will establish the standard against which all resource
acquisitions will be judged, both utility and non-utility owned alike.

Public participation is required in the preparation of utility IRPs. Developers and
their representatives shall be welcome to participate in any public meeting related to the
development of a utility IRP. It is the utility's responsibility to offer invitations to
participate to a broad cross section of interested parties. The responsibility to actually
participate lies with the interested parties.

The opportunity for developers or other interested parties to ultimately influence
the calculation of avoided cost and the rates for QF projects that are derived from that

STAFF PROPOSAL 3
calculation, is in the development of a utility's IRP, not in the application of the avoided
cost methodology. The IRP is the source of all inputs used in the calculation of
avoided costs. It is the real basis for

STAFF PROPOSAL 4
calculating avoided cost rates. Once the avoided cost methodology is established,
Staff does not expect a hearing or other formal Commission proceeding to be initiated
each time a utility's avoided costs are calculated.

General Methodology

PURPA defines avoided cost as "the cost to an electric utility of electrical energy
or capacity or both which, but for the purchase from such cogenerator or small power
producer, such utility would generate itself or purchase from another source" 18 CFR,
292.101.

As explained by FERC:

This definition is derived from the concept of "the
incremental cost of alternative electric energy" set forth in
section 210(d) of PURPA. It includes both the fixed and the
running costs on an electric utility system which can be
avoided by obtaining energy or capacity from qualifying
facilities. One way of determining avoided cost is to
calculate the total (capacity and energy) costs that would be
incurred by a utility to meet a specified demand in
comparison to the cost that the utility would incur if it
purchased energy or capacity or both from a qualifying
facility to meet part of its demand and supplied its remaining
needs from its own facilities. The difference between these
two figures would represent the utility's net avoided cost. In
this case, the avoided costs are the excess of the total
capacity and energy costs of the system developed in
accordance with the utility's optimal capacity expansion plan,
excluding the qualifying facility, over the total capacity and
energy costs of the system (before payment to the qualifying
facility) developed in accordance with the utility's optimal
capacity expansion plan including the qualifying facility.
(Order No. 69 45 Fed. Reg. 12,216, 1980 ).

In the proposed methodology, the avoided cost of a QF project is determined as
the cost which the utility would avoid if it purchased power from the QF, rather than

STAFF PROPOSAL 5
acquiring the same power from the resources selected in its base case resource plan.
Put another way, the avoided cost

STAFF PROPOSAL 6
of the QF project is the difference in the present value of revenue requirements (PVRR)
between the base case resource plan and a modified resource plan that includes the
QF resource. The avoided cost determination involves the following steps:

1. An IRP is prepared for the utility. The IRP should consider a range of load
forecasts for various sets of possible economic conditions. The IRP should also
consider all possible resources for meeting load, both supply side and demand
side. In addition, consideration should be given to the risks and uncertainties
associated with each scenario examined. The least cost combination of
resources is selected to meet each scenario. The most likely scenario is
identified as the base case plan.

2. An initial simulation analysis using a power supply and/or capacity expansion
model chosen by the utility is used to calculate the PVRR of the base case
resource plan over the lifetime of the proposed QF contract.

3. The proposed QF resource is added to the base case resource plan during
all years of the proposed contract. The required description of the QF project
includes all data and information needed to model the intended dispatchable or
non-dispatchable operation of the project on the power supply system (see pps.
9-10 for a list of data and information needed from QFs).

4. A second simulation analysis, including the QF resource, is performed which
results in an adjustment of the amount and/or timing of the new resources in the
base case plan. The modified plan including the QF purchase is constructed to
maintain resource adequacy and system reliability equivalent to that of the base
case plan.

5. The PVRR of the modified resource plan including the QF is calculated over
the full term of the QF contract, excluding the total purchase costs of the QF

STAFF PROPOSAL 7
resource itself.

6. Finally, the present value of the QF project avoided cost is calculated by
subtracting the PVRR of the modified plan, with costs of the QF set to zero, from
the PVRR of the base case resource plan.

7. Rates for capacity and energy from the QF project can now be developed for
which, on a present value basis, the expected payments to the QF are equal to
the project's avoided cost over the life of the contract.

IRP Data for Avoided Cost Calculations

Many of the same variables must be chosen and many of the same assumptions
must be made by each utility in the development of their IRP. For example, each utility
must make assumptions about inflation, the price of natural gas, or the cost of building
a coal plant. Some planning variables will probably be the same for all utilities, but
many will be different. In the past, the Commission has specifically determined both
generic and company-specific variables used to calculate avoided cost for large
projects. With implementation of the IRP methodology, the Companies will be
responsible for determining these variables. As long as the values and assumptions
fall within a reasonable range, utilities are free to choose values most appropriate for
their own situation. It follows then, that different utilities will likely assume different
values for the same variables. No variables will be considered generic; all variables
will be utility specific, as are the utilities' IRPs. In granting utilities the freedom to select
their own variables, utilities should be aware that they will be required to analyze their
own resources on an equal footing with QF resources.

Portfolio Resources

The resource portfolio of each utility should include a variety of both supply and

STAFF PROPOSAL 8
demand side resources. Market purchases also represent a future supply option, and
will likely comprise an increasingly larger portion of utilities' resources in the future. In
fact, for some utilities, market purchases may constitute the primary source of new
resources. The cost of market resources, to the extent a utility relies on them, should
be one component in determining utilities' avoided costs. However, in order for
market resources to be considered in the determination of avoided costs in an
IRP-based methodology, those market resources must be included in the IRP. Any
market purchases made that are not anticipated in the IRP cannot be used in the
calculation of avoided costs. However, due to the fact that Pacificorp s RAMPP-4
calibration of its IPM model does not provide for the IPM s calculation of avoided costs,
Pacificorp will be allowed to propose modifications to the IPM calibrations for the
purpose of determining avoided costs, subject to Commission approval in Case No.
IPC-E-95-9.

Predicting the price and availability of market resources, particularly in the long
term, is difficult and uncertain. Consequently, forecasts made in the IRP should be
firmly based on sound reasoning and analysis. The degree of planned reliance on
market resources should be a matter of interest to ratepayers, shareholders, the
Commission and the public. Review of the utilities' planned reliance on the market
however should occur in the context of an IRP filing, not in an avoided cost proceeding.

Demand side resources to which the utility has made a firm commitment should
be considered as reductions in the load forecast rather than as supply side resources,
in part, to discourage double counting.

Load and Resource Forecasts

Forecasts of electricity load growth are made by each utility at two-year intervals
as a part of IRP filings. These forecasts serve as the basis for avoided cost
calculations. Staff contends that only known, measurable, and easily documented

STAFF PROPOSAL 9
changes should be made to the forecasts during the interim periods between required
filings. For example, discrete changes in load that could be traced to the addition or
loss of a single major customer would be a known, measurable, and easily documented
change. The signing or expiration of a power sales or exchange agreement would also
be a known, measurable, and easily documented change, as would the signing of a
new QF contract. On the other hand, a load change due to population growth may be
known, but would not be easily measured or documented.

Updating IRP Data

For the most part, utilities' resource plans as set forth in their IRPs should guide
resource acquisition activities, including the resource cost effectiveness and avoided
cost determinations, until replaced by subsequent IRPs. One of the goals of this
avoided cost methodology is to achieve a dynamic resource evaluation process that
recognizes changes in loads, technologies, costs, availabilities, and economic
conditions so that utilities' avoided costs are accurately determined. However, QF
developers seek to maintain some stability of avoided cost rates so that they are able to
plan projects with some degree of certainty. In addition, the public must have the
opportunity to participate in the planning process to provide input regarding variables
that are ultimately used in each utility's IRP.

To achieve some balance between these competing objectives, this
methodology allows periodically scheduled changes to some variables, while keeping
other variables fixed between IRP filings. In essence, there will be a core set of
variables that are used in the IRP and in the determination of avoided cost rates, but a
subset of those variables will be changed periodically for the purpose of accurately
calculating avoided costs. Every two years, a new IRP will be filed with new core
variables and variables that will be adjusted periodically.

Generally, variables which are acquired from independent third party sources

STAFF PROPOSAL 10
and which are updated at regular intervals can be adopted by utilities for use in avoided
cost calculations. However, the same source must be consistently used. Any change
in the source of the data must also be agreed to by the Commission. Semi-annual
updates will be allowed for the following based on verifiable forecasts:

Escalation rates for capital costs;
Escalation rates for O&M expenses;
Escalation rate for fuel prices;
Fuel prices.

If multiple sources are used to establish values for these variables, such as for
gas prices, or if a utility wishes to make adjustments to values in consideration of
regional circumstances, the utility should propose the sources and adjustment
mechanisms at the time of their next IRP filing for consideration by the Commission.
The utility should consistently use the same sources and adjustment mechanisms in the
future for determining avoided cost rates unless changes are authorized by the
Commission.

At such time as easily verifiable information is readily available from independent
third party sources, the following variables may also be updated semiannually:

Wholesale power price;
Wholesale power price escalation rates;
Wholesale power available for purchase.

The variables must be reflective of the same wholesale power products used for
analysis in the IRP, so that no adjustment of the variables is needed before they can be
used in the IRP or in calculating avoided cost rates. Permission must be obtained from
the Commission before these variables may be updated on a semi-annual basis for

STAFF PROPOSAL 11
avoided cost purposes.

Staff recommends that updates to resource portfolio data, such as plant capital
costs,
operation and maintenance costs, heat rates, generation capacities, plant factors,
economic life, etc. not be allowed except during biennial IRP submissions. Updates to
load forecasts, except for known and measurable changes as discussed previously,
should also not be allowed except during IRP submissions.
Variables that go into calculating utilities' before and after tax cost of capital
should be updated on a regular basis also. Staff proposes that these variables be
updated biennially upon submission of new IRPs. Utilities may use estimated values
for weighted cost of capital, and should assume a hypothetical capital structure
reflecting the typical degree of leveraging for electric utilities with "A" grade bond
ratings. Alternatively, utilities may use the weighted cost of capital as established in
the utility s most recent general rate case.

To the extent they affect resource costs, the passage of new laws and the
imposition of new regulations may trigger changes in variables. Staff recommends
Commission approval be required however, before variables can be changed for the
purpose of determining avoided costs as a result of these types of factors.

Publication of Rates

In order to provide benchmark avoided cost rates which potential QF developers
can use for planning purposes, Staff recommends utilities be allowed to publish avoided
cost rates for hypothetical projects. The rates should be published semiannually at the
time changes in variables are submitted to the Commission. The rates should be for
hypothetical 10 MW, 20 MW, and 40 MW gas-fired, non-dispatchable projects
with 100% capacity factors. The rates would be non-binding on the utility and would
serve only as an approximation of rates for similar projects. Alternatively, utilities may

STAFF PROPOSAL 12
forego publishing hypothetical rates if they can provide, within 10 working days of
receiving a request, approximate rates based on IRP model runs.

Rate Quotations

Before a developer requests a rate quotation from a utility, Staff recommends a
meeting be held between the utility and the developer to discuss details of the project
and to discuss the process for calculating rates. Once a request for binding rates is
made, Staff contends the utility should

STAFF PROPOSAL 13
respond to the request within 30 days. In order to receive a firm quotation, the
developer must be able to provide the utility with the following information:

1. Developer name;
2. Proof of QF status (notice of self-certification will suffice);
3. Project location, and point of power delivery if the project is located outside
of the state of Idaho;
4. Project size, including ambient conditions for this rating;
5. Capacity factor and proposed time shape of production;
6. Fuel source and mode and route of delivery;
7. Whether fuel supply is firm or non-firm and whether there are any
constraints affecting its availability or dependability;
8. Proposed contract term (final term length and timing to be subject to
negotiation);
9. On-line month and year;
10. Maintenance schedule;
11. Other factors affecting operation;
12. Wheeling utility(ies) between point of interconnection and point of delivery;
13. Expected delivered energy by month during heavy and light load hours;
14. Guaranteed minimum capacity.

If a project desires to be operated according to a negotiated schedule or dispatched
under specific circumstances, the utility may request additional information as needed
in order to provide an accurate rate quotation.

In response to a request for rates, Staff believes the utility should provide the
difference in cost by year between the base case plan and the same plan with the QF
included. Using an acceptable methodology, utilities should separate the annual
differences in costs into capacity and energy components.

STAFF PROPOSAL 14
Actual contract terms should be negotiable between the utility and the developer,
subject to the rules and guidelines set forth in this document. Rate quotations should
be effective for a minimum of 120 days. Except for the signing of other QF contracts,
the acquisition of other generating resources, or major discrete changes in load, under
no other circumstances should the rate be changed during the 120-day period, even if
changes occur in variables. When providing a rate quotation, utilities should be
obligated to divulge whether any other rate quotation has been made for another
project and is still within its 120-day effective period. In addition, utilities must agree to
meet with the developer within 15 working days after the date on which the rate
quotation is made.

Access to Utility Models

Utilities should be allowed to utilize any model they desire in calculating avoided
costs, as long as the same model is used in the development of the utility's IRP. If the
utility is required to sign a licensing agreement for use of the model that restricts its use
to utility personnel only, then access to the model may be restricted to the Commission
Staff, subject to restrictions of the licensing agreement. However, in order to minimize
the "black box" effect created when rates are calculated by the utility using proprietary
software, utilities must be willing to accommodate requests from developers and
Commission Staff for a reasonable number of model runs for alternative project plans.
The model runs must be meaningful and requested in support of negotiating a
commercially viable contract. Staff recommends that no fee be charged by the utility
for these model runs. Furthermore, utilities should have the obligation to assist
developers in optimizing their projects so that developers maximize the value of their
project to the utility's system. To do so is in the best interests of both the developer
and the utility.

Treatment of Non-Deferrable Utility Resources

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A non-deferrable resource is one which, if developed, must be developed at a
certain point in time. Non-deferrable does not mean that a project must be developed.
The inclusion of non-deferrable resources in a utility's IRP may represent the least cost
option, and may, in fact, be a part of a utility's base case plan. However, if
non-deferrable resources are included in a utility's resource plan for purposes of
calculating avoided costs, then the value of a proposed QF may be diminished since it
cannot defer, and may not fully displace, the non-deferrable resource. Since the value
of a QF to the system comes from its ability to defer or displace IRP resources, a QF
that could do neither would have no value. On the other hand, omission of
non-deferrable resources would artificially increase avoided costs. Furthermore,
omitting a non-deferrable resource from avoided cost calculations presumes that it is
not part of the least cost mix of future utility resources. Staff contends that neither full
inclusion nor full exclusion is appropriate but, nevertheless, recommends that
non-deferrable resources be fully included in avoided cost calculations since a workable
middle ground is not apparent.

Seasonalized and On-Peak/Off-Peak Rates

Staff believes utilities should be permitted to continue to offer different rates for
peak and off-peak hours, and to continue to seasonalize rates (where currently allowed
for Idaho Power and Washington Water Power) using the same seasonalization factors
allowed for projects smaller than 1 MW.

STAFF PROPOSAL 16
rs:gdk:jo:bp/ipce959b.avc/h (4-24-96)