20071005Comments.pdf

SCOTT WOODBURY
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
ISB NO. 1895
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IDAHO PUBLIC
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UTiLITIES COMMISSlul\
Street Address for Express Mail:
472 W. WASHINGTON
BOISE, IDAHO 83702-5983
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE PETITION OF
ROCKY MOUNTAIN POWER FOR AN ORDER)
REVISING CERTAIN OBLIGATIONS TO
ENTER INTO CONTRACTS TO PURCHASE
ENERGY GENERATED BY WIND-POWERED
SMALL POWER GENERATION QUALIFYINGFACILITIES.
CASE NO. PAC-O7-
COMMENTS OF THE
COMMISSION STAFF
COMES NOW the Staff ofthe Idaho Public Utilities Commission, by and through its
Attorney of record, Scott Woodbury, Deputy Attorney General, and in response to the Notice of
Modified Procedure and Notice of Comment /Protest Deadline issued on August 22 2007 in Case No.
P AC- E-07 - 7, submits the following comments.
BACKGROUND
On April 23 , 2007, PacifiCorp dba Rocky Mountain Power (PacifiCorp; Company) filed an
Application with the Idaho Public Utilities Commission (Commission) requesting a change in the
Company s PURPA obligations for wind QFs. PacifiCorp proposes restoring the cap on entitlement
to published avoided cost rates for wind-powered small power generation facilities that are qualifying
facilities (QFs) under Sections 201 and 210 of the Public Utility Regulatory Policies Act of 1978
STAFF COMMENTS OCTOBER 5 , 2007
(PURP A) from the current level of 100 kW to 10 average megawatts per month (10 aMW), subject to
the following conditions:
1. Reducing the published avoided cost rates applicable to purchases by
PacifiCorp of electric power from wind-powered QFs by $5.04 per MWh
which amount represents the inflation-adjusted integration costs of that wind
power, to be applied against published avoided cost rates except in those
circumstances where the QF developer agrees in the power purchase
agreement with PacifiCorp to deliver QF output to PacifiCorp on a firm
hourly schedule;
2. Removing the requirement that the 90%/110% performance band be applied
to purchases from wind-powered QFs;
3. Authorizing PacifiCorp to purchase state-of-the-art wind forecasting services
to provide PacifiCorp with forecasted wind conditions in those geographic
areas in which wind generation resources are located, provided that QFs will
reimburse PacifiCorp for their share of the on-going cost of the wind
forecasting service, in proportion to their percentage share of the wind-
generator capability being supplied to PacifiCorp from that area;
4. Requiring QFs to deliver a "mechanical availability guarantee" to PacifiCorp
to demonstrate monthly, except for scheduled maintenance and events of force
majeure or uncontrollable force, that the QF was physically capable and
available to generate a full output during 85% of the hours in a month;
5. ... (Disaggregation issue - separately noticed on June 28, 2007)
6. Clarifying that the cap on entitlement to published avoided cost rates shall be
restored to 10 aMW only until PacifiCorp s renewable targets for each
calendar year in the most recently acknowledged Integrated Resource PIan are
met.
A Notice of Petition in Case No. PAC-07-7 was issued on May 15, 2007. A Notice of
Discussion Regarding Procedure was issued on June 4 2007. On June 28 2007, the Commission
issued a Notice establishing an intervention deadline of July 18, 2007. The following parties
requested and were granted intervenor status: Intermountain Wind LLC; Exergy Development Group
of Idaho LLC; Renewable NW Project and NW Energy Coalition; Idaho Windfarms LLC; Avista
Corporation; and INL Biofuels and Renewable Energy Technologies.
On July 31 and August 10 2007, Commission Staff sponsored joint settlement workshops in
Case Nos. PAC-07-7 (PacifiCorp), IPC-07-3 (Idaho Power), and A VU-07-2 (Avista) to
explore whether parties of record could agree to a common generic wind integration adjustment to
STAFF COMMENTS OCTOBER 5 , 2007
published rates. IDAPA 31.01.01.272-276. The parties were unable to reach settlement during these
workshops.
On October 1 , 2007, however, several weeks after the unsuccessful settlement workshops
Renewable Northwest Project and Northwest Energy Coalition (together
, "
RNP") submitted a
Settlement Stipulation signed by it; PacifiCorp; Idaho Windfarms, LLC; and the Commission Staff.
The following comments are submitted in support of the Settlement Stipulation. Similar Settlement
Stipulations have been submitted concurrently in cases for Avista (A VU-07-2) and PacifiCorp
(P AC-07- 7); consequently, Staffs comments address the Stipulations reached in those cases as
well due to the parallel issues in the three cases.
ANALYSIS
Although there are several secondary issues in this case (90/110 performance band
mechanical availability guarantee, wind forecasting) the primary issue is wind integration costs.
PacifiCorp performed its own wind integration study using its own staff as a part of its integrated
resource planning (IRP) process. Wind integration studies are rather new, and the techniques for
modeling wind and conducting wind integration studies are rapidly evolving. Besides PacifiCorp
study, other studies have been done around the u.s. and in Europe. Comparisons are frequently
made between various wind integration studies. Sometimes those comparisons are made simply to
show how wind integration costs vary between different electrical systems. Other times comparisons
are used to judge the reasonableness of study results, sometimes implying that studies showing costs
far outside of the range of other studies must somehow be inferior or inaccurate.
Wind integration costs differ from one system to the next just as electric rates differ between
systems. Direct comparisons between integration costs for various utilities are often invalid unless
they recognize differences in generation fleets, resources available to integrate wind, the size and
resources in the utility s control area, the structure of the real-time market, and most importantly, the
difference in value of generation that is moved from on-peak to off-peak times, both on a daily and a
seasonal basis to integrate wind.
Fpr example, it is not intuitive that integration costs in a mostly hydro-based system will be
higher than costs in a system where gas is used as the primary marginal resource. The costs of wind
integration, however, are driven not so much by the costs ofthe dispatchable resource used for
integration, but are instead driven more by the difference in cost between the dispatchable resource
STAFF COMMENTS OCTOBER 5 , 2007
and the market price at the time integration takes place. In a hydro-based system, wind integration is
primarily achieved by moving extremely low cost hydro generation from hours when it is most
valuable to hours when it is least valuable. In a thermal based system where gas is primarily used for
integration, there is much less "opportunity cost" in shifting gas-fired generation from high value
hours to low value hours.
The studies done by PacifiCorp, Idaho Power and Avista relied on the best available analysis
tools and expertise, and, Staff believes, are as credible as any other study done previously in the U.
While Staff does not believe that other studies are directly comparable to PacifiCorp , Idaho
Power , and A vista , those other studies do demonstrate that wind integration costs can be lower in
systems where there is greater geographic diversity, larger control areas, greater amounts of quickly
dispatchable thermal generation, and shorter real-time markets. Other studies can serve to provide
indications that integration costs could become less in Idaho if conditions change in the future.
Wind Integration Cost Uncertainty
One thing that is clear from any wind integration study is that wind integration is imprecise
and uncertain. Idaho Power, in fact, recognizes this in its Petition in Case IPC-07-3 wherein it
states "The wind integration study makes it clear that there is still a great deal of uncertainty
surrounding the ultimate impact and cost of adding large amounts of wind generation to the
Company s resource portfolio." (Petition page 8). Staff agrees. Workshops held to review the
results of the utilities ' integration studies highlighted the broad range of possible outcomes that could
be achieved by varying the assumptions for numerous variables used within the study.
Part of this imprecision and uncertainty is due to the difficulty of modeling the intermittent
nature of the wind, the generation it produces and its effect on the rest of the electrical system.
Another reason is the many assumptions that have to be made in the analysis. For example
assumptions have to be made about the magnitude, locations and timing of future wind generation
development; wind forecasting effectiveness, geographic diversity of wind resources; size, height and
other characteristics of expected wind turbines; reserve requirements; future electric market structures
and pricing; resources available to provide reserves; and operating constraints of existing generation
plants. Staff believes that reasonable arguments could be made to justify combinations of differences
in assumptions that result in widely varying integration costs.
STAFF COMMENTS OCTOBER 5, 2007
Another thing that is immediately clear from wind integration studies is that wind integration
costs vary as conditions change, and are different under different water conditions, electric market
conditions, and wind penetration levels. Because conditions are never the same, some type of
average wind integration costs must be used to reflect costs over the long term.
It should also be noted that the avoided cost methodology established to produce the
published rate for small projects is itself based on a broad range of assumptions designed to produce a
proxy, 20-year levelized contract price. It is not an exact science and adjusting that price for
integration costs using an assumption driven system model does not appear to be an exact science
either.
Wind Integration Costs are Small Compared to Avoided Cost Rates
One of the primary purposes of this proceeding is to determine whether a wind integration
adjustment should be applied to published avoided cost rates. Staff believes it is very important to
keep the magnitude of an adjustment in perspective, considering the imprecise and uncertain nature of
the wind integration studies. The difference between the $7.92 per MWh proposed by Idaho Power
in Case No IPC-07-3 and the $5.04 per MWh proposed by PacifiCorp in this case is $2.88 per
MWh, a relatively small amount when compared to the utilities' 20-year levelized published avoided
cost rate of about $64 per MWh.
Wind Integration Adjustments and 20- Year Power Sales Contracts
Published avoided cost rates are computed for contract lengths up to 20 years. Computation
of the avoided cost rates relies on assumptions about capital and 0 & M costs and forecasted fuel
costs that are intended to be representative over the entire 20-vear contract period. Once signed, the
avoided cost rates in PURP A contracts are not adjusted throughout the term of the contract.
To be consistent, any wind integration adjustment that is applied to avoided cost rates should
also reflect a long-term expectation of what those wind integration costs will be over the entire 20-
year period, not just what integration costs might happen to be now. Staff expects that wind
integration costs are likely to decrease over the 20-year future for a variety or reasons. For example
energy storage technologies involving batteries, compressed air, capacitors, flywheels, and even
electric automobiles are likely to advance in the future. New technologies are also bound to emerge.
Electric markets are also likely to evolve to better accommodate intermittent generation. Finally,
STAFF COMMENTS OCTOBER 5 , 2007
utility practices will improve as more experience and confidence is gained with wind generation. In
fact, in response to production requests in Case No. IPC-07-, Idaho Power stated
, "
Idaho Power
has acknowledged that as experience is gained in operating its system with greater amounts of wind
generation and potential cooperative agreements between control areas are developed, a future
analysis of the impact of wind generation may indicate a lower cost of integration." (Reference Idaho
Power response to Request for Production No.2 of the Renewable Northwest Project and NW Energy
Coalition).
Some of the utilitie~' wind integration studies anticipate changes in geographic diversity and
transitions in electric market structures, but it is nearly impossible to envision all of the changes that
could take place over the next 20 years. In the same way that avoided cost rates are a long-term
estimate, wind integration costs must also be considered over the long term. Because not all future
changes likely to affect wind integration costs can be known with certainty now, Staff believes some
degree of speculation is required.
Idaho Power s Wind Integration Study
As stated previously, Idaho Power utilized the expertise and experience of EnerNex and Wind
Logics to assist in completing its wind integration study. Idaho Power s study has been subject to
considerable peer review from the Northwest Wind Integration Plan members and others. It has also
been the focus of most of the intervenors in this case because its wind integration study results were
initially the highest of the three utilities and because there seems to be the most interest in siting
projects in Idaho Power s service territory.
Idaho Power has indicated that geographic diversity of wind, transmission constraints, hourly
market structure and limited resources to provide reserves are factors that increase its wind
integration costs above those found in other areas of the country. In its Petition, the Company
proposed a fixed rate adjustment of$10.72 per MWh. This was later reduced to $7.92 per MWh after
additional studies and analyses incorporating acceptable modification of study assumptions were
completed during the public and peer review process. Costs were reduced even further to $5.88 per
MWh based on an assumption that the Company s share of the coal-fired Bridger plant could be used
for down-regulation. Idaho Power dismisses this possibility for now, however, because it does not
believe that the Bridger plant could realistically be operated in the manner assumed by the studies.
STAFF COMMENTS OCTOBER 5, 2007
Avista s Wind Integration Study
Like Idaho Power, Avista also hired EnerNex to assist with portions of its study; however
Avista performed the majority of its analysis using its own staff. Avista s study has been subject to
considerable peer review, although its study has received less scrutiny than Idaho Power , primarily,
in Staffs opinion, because Avista s wind integration costs were below Idaho Power s initial results
and because there is less interest from wind developers in siting projects in Avista s service territory.
Avista proposed a wind integration adjustment of 12 percent of published avoided cost rates
which equated to $7.57 per MWh on a levelized basis for a 20-year contract. If some type of outside
firming service is purchased and an hour-ahead firm product is delivered to Avista by the wind
project, the Company proposed that the wind integration adjustment be reduced by half.
PacifiCorp s Wind Integration Study
PacifiCorp proposed a wind integration adjustment of$5.04 per MWh. The adjustment
based on studies conducted initially by the Company s own staff as part of the development of its
2004 Integrated Resource Plan. Wind integration costs have been updated to $5.10 its 2007 IRP
which is still pending Commission acceptance. Because PacifiCorp conducted its studies much
earlier than either Idaho Power or Avista, the analysis lacks some of the sophistication ofthe later
studies and may not fully account for all components of wind integration costs. In addition, the
analysis may be a bit more outdated than others. Because PacifiCorp s study was just one small
element of the much larger exercise of developing an Integrated Resource Plan (IRP), the wind
integration study has been subjected to far less scrutiny and peer review than either of the other two
utilities' studies. PacifiCorp has never prepared a report presenting the details and results of its wind
integration study. Instead, a description of its study and results is contained in a mere 2Yz-page
appendix of its IRP. With such minimal documentation ofPacifiCorp s study, it is difficult to judge
its accuracy or to contrast its results with those of Idaho Power and A vista.
Wind Integration Adjustment to Avoided Cost Rates
Based on the uncertainty in assumptions used in the integration studies and the impact that
uncertainty has on estimated adjustment to published rates, and based on the fact that wind
integration costs must be estimated 20 years into the future, Staff believes it is reasonable to accept
the wind integration charges included in the Settlement Stipulation as reasonable approximations of
STAFF COMMENTS OCTOBER 5, 2007
wind integration costs going forward. Wind integration costs as proposed in the Stipulation, as a
percentage of avoided cost rates, are as follows:
Idaho Power
Amount of wind online
0 to 300 MW
301 to 500 MW
501 MW and above
Integration cost adjustment as a
percentage of avoided cost rates
A vista
Amount of wind online
0 to 199 MW
200 to 299 MW
300 MW and above
Integration cost adjustment as a
percentage of avoided cost rates
PacifiCorp
A wind integration cost adjustment of $5.04 for all new PURP A wind projects.
ForPacifiCorp, the proposed fixed wind integration cost adjustment of $5.04/ MWh for all
wind projects compares favorably with variable cost adjustments proposed for both Idaho Power and
A vista. At seven percent of current published avoided costs rates the adjustment would be
$4.39/Mwh for a 20-year contract with a 2007 online date and $5.65/Mwh at nine percent. Under the
terms of the PacifiCorp Stipulation, the amount of the integration charge is fixed at the $5.04 level
and will not increase with increases in avoided costs rates nor will it change with the amount of wind
online.
Staff believes the differences in the proposed wind integration adjustments recognize the
utility-specific characteristics of the three utilities and the relative sophistication of the three
integration studies. Staff also believes that the larger service territory ofPacifiCorp, which reduces
the limitations of available resources, transmission and wind diversity in conjunction with greater
operation and forecasting experience, justifies a somewhat smaller integration cost adjustment. Staff
further believes it is reasonable to fix the wind integration adjustment as proposed in the PacifiCorp
Stipulation rather than escalate the rate at increasing wind penetration levels given that the proposed
rate already assumes a 20% wind penetration level.
STAFF COMMENTS OCTOBER 5 , 2007
Staff believes the proposed integration costs are a reasonable long-term estimate over the
typical20-year PURP A contract term. Periodic reviews as provided for in the Stipulation will
provide opportunities to revise the adjustment if downward and upward pressures on wind integration
costs get out of balance.
Wind Forecasting
All parties in this case seem to agree that forecasting can be valuable and that it can help to
reduce integration costs. The disagreement lies in who should bear the cost of wind forecasting. The
utilities contend that forecasting costs are the responsibility of the project owner, because ifnot for
the project, there would be no need for the forecasting. Project owners contend that if they are
charged with the cost of forecasting, then the wind integration discount applied by the utility should
be less due to the benefits of forecasting in lowering integration costs. Still others contend that the
utilities and the project owners both benefit from forecasting and conclude that costs should be shared
in proportion to the value of benefits received by each.
Staff supports the rationale that both parties benefit from forecasting and therefore should
share the costs. Furthermore, Staff acknowledges that the costs of forecasting are relatively small.
Staff supports the terms of the Settlement Stipulation that give PacifiCorp sole discretion for
determining whether forecasting is necessary or desirable. In addition, should forecasting be deemed
necessary or desirable, Staff supports the terms of the Settlement Stipulation under which forecasting
costs will be shared equally, subject to a cap on the wind QF's potential liability for such costs set at
1 percent of project revenues.
Mechanical Availability Guarantee
Both the wind project developers and the utilities in this case support a requirement for a
Mechanical Availability Guarantee (MAG). Under a MAG, projects would have to insure that they
are mechanically available to operate some specified percentage of time in order to be eligible for
discounted published avoided cost rates. Staff contends that project owners already have very strong
incentive to insure mechanical availability-if equipment is not mechanically available, there can be
no generation, thus no revenue. Nevertheless, Staff supports the MAG requirement as proposed in
the Stipulation.
ST AFF COMMENTS OCTOBER 5, 2007
The MAG concept seems simple, but Staff believes that application of the MAG requirement
in practice is more complicated. First, enforcement of the MAG will be difficult. The only real proof
a turbine was available to operate during a month is whether it in fact operated. When the wind is not
blowing, or is blowing at less than cut-in speed or more than cut-out speed there is no way to confirm
mechanical availability other than the word of the developer. To make enforcement easier and
consistent between utilities, Staff proposes that these hours not be counted for purposes of computing
mechanical availability. Confirmation of availability when there is enough wind to operate requires
that accurate hourly wind speed data be collected, and that computations be made using this data and
corresponding electrical generation data. Multiple turbines (which nearly all projects will have)
complicate the computation of availability because some turbines may be mechanically available and
others not. Staff recommends that if a MAG requirement is adopted, that the MAG requirement be
85 percent of all hours during the month when wind speed is between the turbines' cut-in and cut-out
speed, and that electrical output be measured on a project basis rather than an individual turbine basis.
Periodic Updates to Wind Integration Costs
If the Commission adopts an adjustment to published avoided cost rates to account for wind
integration costs, Staff believes that such an adjustment should be subject to periodic review. Each
the utilities' wind integration studies have shown that integration costs escalate as penetration levels
increase. At the same time, however, wind integration costs will likely decrease over time as utilities
gain more experience integrating wind, as forecasting improves, as ancillary services markets evolve
and as technology advances. Whether the factors causing integration costs to increase completely
offset the factors causing integration costs to decrease remains to be seen. Moreover, the study of
wind integration costs itself is evolving. With each new integration study that is conducted, new
knowledge is gained and new tools developed for better assessing wind integration costs. For all of
these reasons, Staff believes that wind integration adjustments established today will not necessarily
be the appropriate amounts for contracts that may be signed several years from now.
One option is to simply escalate wind integration costs as wind penetration levels increase in
accordance with the results of each utility s wind integration study. This approach ignores the
likelihood, however, that wind integration technology and practices will improve over time. As
result, Staff does not recommend this approach.
STAFF COMMENTS OCTOBER 5 , 2007
A much better approach, Staff believes, is to permit periodic reviews of wind integration costs
in the same way that the variables used to compute avoided cost rates are subject to periodic review.
Under the avoided cost methodology, parties can petition the Commission at any time to open a
docket to review and update variables if those variables are believed to be outdated or inaccurate.
This approach recognizes that each utility might have a different integration cost, but synchronizes
the timing of review of all three utilities' integration costs so that interested parties can coordinate
their efforts and so that appropriate comparisons can be made between utilities.
Under the terms of the Settlement Stipulation, PacifiCorp will convene an informal wind
integration working group which will meet at least two times during 2008 to discuss PacifiCorp
wind integration study and new data related to wind integration costs. In addition, PacifiCorp will
review wind integration costs as part of its integrated resource planning process in the same way that
costs for other generating resources are included. These provisions will help to insure that wind
integration costs are regularly scrutinized, and will alert parties about when to possibly make
application to the Commission to open a docket for the purpose of updating avoided cost computation
variables, including wind integration adjustments.
Cap on Entitlement to Published Rates
All three utilities have proposed that some sort of cap on entitlement to published rates be
imposed once a specified wind penetration level is reached within each utility's respective service
territory. In most cases, the proposed "cap" is simply a requirement that wind integration costs be
reevaluated at specified penetration levels, although this is not completely clear or consistent in each
utility s application. For purposes of clarification, Staff assumes that each utility s proposal is a
requirement to reexamine integration costs at specified intervals, not a proposal that the utility be
excused from its obligation under PURP A to purchase additional wind generation after certain wind
penetration levels have been reached. Excusing utilities from their obligations under PURP A is not
something the Commission can do, Staff believes, regardless of the quantity of wind offered for
purchase or ofthe utility s cost or difficulty in integrating it.
Elimination of 90/110 Performance Band
Each of the utilities proposes that the 90/110 percent performance band requirement be
eliminated if a wind integration discount and the other proposed contract provisions for wind are
STAFF COMMENTS OCTOBER 5 , 2007
adopted. The original purpose of90/110 percent performance requirement, Staff believes, was to
insure that projects provided a degree of firmness sufficient to make them reasonably comparable to
other utility and market resources normally priced at what have historically been known as "firm
energy" rates. Prior to this time, all wind generation was assumed to be non-firm and therefore
eligible only for market-based non-firm energy prices. By requiring a degree of predictability in
order to qualify for firm energy rates, utilities attempted to better match the prices it was required to
pay with more standard industry definitions of the product it received.
The adoption of a wind integration adjustment, a MAG, and wind forecasting really do
nothing to increase the firmness of wind generation on a long-term basis. There is still no assurance
for example, that the wind will be blowing on a specific day or at a specific time in the future when
the utility most needs the generation. These measures do, however, financially account for wind'
intermittency on a short-term basis, and are, Staff believes, an acceptable substitute for the 90/110
percent performance band requirement.
With implementation of a reasonable integration cost adjustment for wind, a measured
approach to wind forecasting and adoption of a verifiable MAG, Staff supports elimination of the
90/110-performance guarantee as discussed in the Settlement Stipulation. For non-wind resource
types not subject to the integration adjustment, Staff recommends that the 90/110 requirement be
retained.
Availability of Terms From This Case to Existing Contracts
The Settlement Stipulation proposes that terms accepted by the Commission in this case as
required conditions for new contracts be available to existing wind contracts should they wish to be
renegotiated. For example, the Stipulation suggests that existing contract be able to be renegotiated
to remove the 90/110 performance requirement and impose a MAG requirement in exchange for
avoided cost rates discounted by a wind integration adjustment.
Staff has no objection to renegotiation of existing contracts, provided that all of the terms of
the Stipulation are included in the amended contracts (i., elimination of the 90/110 provision
inclusion of the 85% MAG requirement, sharing of forecasting costs, and application of an
integration adjustment). In addition, Staff believes that the wind integration adjustment must be
applied to the rates contained in the original contract and not to whatever avoided cost rates may be in
effect at the time the contract is renegotiated.
STAFF COMMENTS OCTOBER 5 , 2007
RECOMMENDATIONS
Staff recommends that the cap on entitlement to published avoided cost rates for intermittent
wind-powered small power production facilities that are qualifying facilities (QFs) under Sections
201 and 210 of the Public Utility Regulatory Policies Act of 1978 (PURP A) be raised from the
current level of 100 kW to 10 aMW per month. Staff further recommends that the Commission
accept the PacifiCorp Settlement Stipulation containing the following:
A wind integration cost adjustment of$5.04 should be applied to the published avoided cost
rates ofPacifiCorp for all new PURP A wind projects.
The 90/110 percent performance band requirement should be eliminated for all wind
resources.
A mechanical availability guarantee of 85 percent should be required for all new contracts.
The costs for wind forecasting services, should PacifiCorp determine that forecasting is
necessary or desirable, should be shared equally between the utility and the wind project
owner, with a cap on the wind project's potential liability for forecasting costs set at 0.
percent of annual project revenues.
Wind integration costs should be subject to periodic review through informal working groups
and through the IRP process, and possible future updates to wind integration costs should be
made as part of a docketed case to review all variables used to compute avoided cost rates.
There should be no cap on entitlement to published avoided cost rates.
Holders of existing contracts for wind projects should be permitted to renegotiate those
contracts, provided that all of the terms and conditions included in the Stipulation are adopted
and that the rates in the contract are based on those that were in place at the time of the
original contract signature.
Respectfully submitted this -5' day of October 2007.
Scott Woodbury
Deputy Attorney General
Technical Staff: Rick Sterling
Randy Lobb
i:umisc:comments/paceO7.7swrps comments 2
STAFF COMMENTS OCTOBER 5, 2007
CERTIFICATE OF SERVICE
HEREBY CERTIFY THAT I HAVE THIS 5TH DAY OF OCTOBER 2007
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. PAC-07-, BY MAILING A COpy THEREOF, POSTAGE PREPAID
TO THE FOLLOWING:
DEAN BROCKBANK
SENIOR COUNSEL
ROCKY MOUNTAIN POWER
201 S MAIN ST STE 2300
SALT LAKE CITY UT 84111
MAIL: dean. brockbank~pacificorp. com
DATA REQUEST RESPONSE CENTER
P ACIFICORP
825 NE MUL TNOMAH STE 2000
PORTLAND OR 97232
MAIL: datarequest~pacificorp.com
DEAN 1. MILLER
McDEVITT & MILER LLP
PO BOX 2564
BOISE, ID 83701-2564
MAIL: ioe~mcdevitt-miller.com
DR DON READING
6070 HILL ROAD
BOISE ID 83702
MAIL: dreading~mindspring.com
KEN DRAGOON
RENEW ABLE NORTHWEST PROJECT
917 SW OAK ST SUITE 303
PORTLAND OR 97205
MAIL: ken~rnp.org
R. BLAIR STRONG
JERRYK. BOYD
PAINE HAMBLEN LLP
717 W SPRAGUE, SUITE 1200
SPOKANE W A 99220
MAIL: r.blair.strong~painehamblen.com
BRIAN DICKMAN
ACIFICORP
DBA ROCKY MOUNTAIN POWER
201 S MAIN ST STE 2300
SALT LAKE CITY UT 84111
MAIL: brian.dickman~pacificorp.com
STEPHENE. MARTIN
INTERMOUNTAIN WIND LLC
425 S. HOMES
PO BOX 3189
IDAHO FALLS, ID 83403-3189
PETER J RICHARDSON
RICHARDSON & O'LEARY PLLC
PO BOX 7218
BOISE ID 83702
MAIL: peter~richardsonandoleary.com
WILLIAM MEDDlE
ADVOCATES FOR THE WEST
610 SW ALDER ST SUITE 910
PORTLAND OR 97205
MAIL: beddie~advocateswest.org
GLENN IKEMOTO
IDAHO WINDF ARMS LLC
672 BLAIR AVENUE
PIEDMONT CA 94611
MAIL: glenni~pacbell.net
MICHAEL G ANDREA
STAFF ATTORNEY
A VISTA CORPORATION
1411 EMISSION AVE, MSC-
SPOKANE W A 99202
MAIL: michael.andrea~avistacorp.com
CERTIFICATE OF SERVICE
GARY SEIFERT PE
KURT MYERS PE
INL BIOFUELS & RENEWABLE ENERGY
TECHNOLOGIES
2525 S FREMONT AVE
PO BOX 1625/ MS 3810
IDAHO FALLS ID 83415-3810
MAIL: garv.seifert~inl.gov
kurt.m yers~inl. gov
0l~x~SECRETARY
CERTIFICATE OF SERVICE