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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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
VISTA CORPORATION FOR AN ORDER
REVISING A VISTA CORPORATION'
OBLIGATIONS TO ENTER INTO CONTRACTS)
TO PURCHASE ENERGY GENERATED BY
WIND-POWERED SMALL POWER
GENERATION FACILITIES.
CASE NO. A VU-O7-
COMMENTS OF THE
COMMISSION STAFF
COMES NOW the Staff of the 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. A VU-07-, submits the following comments.
BACKGROUND
On April 2, 2007, Avista Corporation (Avista; Company) filed an Application with the
Idaho Public Utilities Commission (Commission) requesting a change in the Company s PURPA
obligations for wind QFs. Avista proposes raising 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 (PURPA) from the
ST AFF COMMENTS OCTOBER 5, 2007
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 A vista
of electric power from wind-powered QFs by 12%, as a percentage
reduction to be applied against scheduled avoided cost rates except where
the QF developer agrees in the power purchase and sale contract with A vista
to deliver QF output to Avista on a firm hourly schedule, in which case the
percentage reduction shall be 6%;
2. Removing the requirement that the 90%/110% performance band
requirement not be applied to purchases from wind powered QFs;
3. Authorizing A vista to purchase state-of-the-art wind forecasting services to
provide Avista with forecasted wind conditions in those geographic areas in
which wind generation resources are located, provided that QFs will
reimburse A vista for their share of the ongoing cost of the wind forecasting
service, in proportion to their percentage share of the wind-generator
capability being supplied to A vista from that area;
4. Requiring QFs to deliver a "mechanical availability guarantee" to Avista 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 raised to 10 aMW only until A vista s total wind portfolio from all
sources totals 400 MW.
A Notice of Petition in Case No. A VU-07-2 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: Exergy Development Group ofldaho LLC;
Renewable NW Project and NW Energy Coalition; Idaho Windfarms LLC; and INL Biofuels and
Renewable Energy Technologies.
On July 31 and August 10 2007, Commission Staff sponsored joint settlement workshops in
Case Nos. A VU-07-2 (Avista), IPC-07-3 (Idaho Power), and PAC-07-7 (PacifiCorp) to
STAFF COMMENTS OCTOBER 5, 2007
explore whether parties of record could agree to a common generic wind integration adjustment to
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, A vista 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. To
assist in determining its wind integration costs, Avista hired EnerNex, arguably the leading u.S.
consulting firm in the area of wind integration studies. EnerNex provided valuable expertise and
experience that supplemented the work of Avista s own staff.
Wind integration studies are rather new, and the techniques for modeling wind and
conducting wind integration studies are rapidly evolving. Prior to Avista s 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.
For 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
STAFF COMMENTS OCTOBER 5 , 2007
integration, however, are driven not so much by the costs of the dispatchable resource used for
integration, but are instead driven more by the difference in cost between the dispatchable resource
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 Idaho Power and A vista relied on the best available analysis tools and
expertise, and, Staff believes, are as credible as any other study done previously in the U.S. While
Staff does not believe that other studies are directly comparable to Idaho Power , Avista s and
PacifiCorp , 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, recognized this in its Petition in Case No. 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." (Idaho Power 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
STAFF COMMENTS OCTOBER 5, 2007
generation plants. Staff believes that reasonable arguments could be made to justify combinations
of differences in assumptions that result in widely varying integration costs.
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 $7.57 per MWh proposed by Avista in
this case (levelized equivalent of 12%) and the $5.04 per MWh proposed by PacifiCorp in Case No.
P AC-07- 7 is $2.53 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-year contract period. Once signed, the
avoided cost rates in PURP A contracts are not adjusted throughout the term ofthe 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
STAFF COMMENTS OCTOBER 5, 2007
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, utility practices will improve as more experience and confidence is gained with wind
generation. In fact, in response to production requests, Idaho Power in Case No. IPC-07-3 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 utilities' 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
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 ofthe coal-fired Bridger plant
could be used for down-regulation. Idaho Power dismisses this possibility for now, however
STAFF COMMENTS OCTOBER 5, 2007
because it does not believe that the Bridger plant could realistically be operated in the manner
assumed by the studies.
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
initial results and because there is less interest from wind developers in siting projects in Avista
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 is
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 A vista, the analysis lacks some of the sophistication of the 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.
STAFF COMMENTS OCTOBER 5, 2007
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
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.
For Avista, seven percent of current published avoided cost rates is $4.42 for a 20-year
contract with a 2007 online date. At nine percent, the integration cost would be $5.68 based on
current avoided cost rates. Under the terms of the Stipulation, the amount of the integration charge
would be capped at $6.50 so that it could not exceed this amount as avoided cost rates increase in
the future.
Staff believes the proposed wind integration adjustments balance the utility specific
attributes identified in the integration studies of both Idaho Power and Avista while recognizing that
neither of these utilities currently has the necessary amount of wind resources online to justify the
level of wind integration costs reported in the studies and proposed initially by the companies. Staff
also believes that the larger service territory ofPacifiCorp, which reduces the limitations of
STAFF COMMENTS OCTOBER 5 , 2007
available resources, transmission and wind diversity in conjunction with greater operation and
forecasting experience, justifies a somewhat smaller integration cost adjustment.
The proposed integration costs, because they are significantly below the values determined
in the utilities' wind integration studies , acknowledge that over time integration costs should
decrease as markets mature, geographic diversity improves, technology advances, and experience is
gained in operation and forecasting. Staff believes the proposed integration costs are a reasonable
long-term estimate over the typical 20-year PURP A contract term. The Stipulation also recognizes
however, that integration costs will increase as greater amounts of wind come online, a result that
was apparent from the studies of both Idaho Power and Avista. 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 if not
for the proj ect, there would be no need for the forecasting. Proj ect 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 A vista sole discretion for
determining whether forecasting is necessary or desirable because Staff believes that Avista will be
much less likely to add substantial amounts of wind generation to its system in the near future. 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 0.1 percent oftotal energy payments made by
Avista to the wind QF.
STAFF COMMENTS OCTOBER 5, 2007
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.
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
of 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.
STAFF COMMENTS OCTOBER 5, 2007
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 a
result, Staff does not recommend this approach.
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, A vista will convene an informal wind
integration working group which will meet at least two times during 2008 to discuss A vista s wind
integration study and new data related to wind integration costs. In addition, A vista 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
STAFF COMMENTS OCTOBER 5 , 2007
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 of the 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
adopted. The original purpose of 90/11 0 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's 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/ll0-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
STAFF COMMENTS OCTOBER 5 , 2007
renegotiated. For example, the Stipulation suggests that existing contracts 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.
Staffhas 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.
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 (PURPA) be raised from the
current level of 100 kW to 10 aMW per month. Staff further recommends that the Commission
accept the A vista Settlement Stipulation containing the following:
An integration cost adjustment as shown below should be applied to the published avoided
cost rates of A vista for all intermittent PURP A resources, subject to a cap of $6.50 per
MWh.
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
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 A vista 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 0.1
percent of total energy payments made by Avista to the wind QF.
STAFF COMMENTS OCTOBER 5, 2007
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 'f1". day of October 2007.
Scott Woodbury
Deputy Attorney General
Technical Staff: Rick Sterling
Randy Lobb
i:umisc:comments/avue07.2swrps 10507
STAFF COMMENTS OCTOBER 5 , 2007
CERTIFICATE OF SERVICE
HEREBY CERTIFY THAT I HAVE THIS
TH DAY OF OCTOBER 2007
SERVED THE FOREGOING REPLY COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. AVU-07-, BY MAILING A COpy THEREOF, POSTAGE PREPAID, TO
THE FOLLOWING:
R BLAIR STRONG
JERRY K BOYD
PAINE HAMBLEN LLP
717 W SPRAGUE AVE SUITE 1200
SPOKANE WA 99201-3505
. E-MAIL: rbrtrongi0painehamblen.com
CLINT KALICH
MANAGER OF RESOURCE PLANNING
A VISTA CORPORATION
PO BOX 3727
SPOKANE W A 99220-3727
PETER J RICHARDSON
RICHARDSON & O'LEARY PLLC
PO BOX 7218
BOISE ID 83702
MAIL: peteri0richardsonandoleary.com
DR DON READING
6070 HILL ROAD
BOISE ID 83702
MAIL: dreading~mindspring.com
WILLIAM MEDDlE
ADVOCATES FOR THE WEST
610 SW ALDER ST SUITE 910
PORTLAND OR 97205
MAIL: beddiei0advocateswest.org
KEN DRAGOON
RENEWABLE NORTHWEST PROJECT
917 SW OAK ST SUITE 303
PORTLAND OR 97205
MAIL: ken~rnp.org
GLENN IKEMOTO
IDAHO WINDF ARMS LLC
672 BLAIR AVENUE
PIEDMONT CA 94611
MAIL: glenni~JJacbell.net
GARY SEIFERT PE
KURT MYERS PE
INL BIOFUELS & RENEWABLE ENERGY
TECHNOLOGIES
2525 S FREMONT AVE
PO BOX 16251 MS 3810
IDAHO FALLS ID 83415-3810
MAIL: gary.seiferti0inl.gov
kurt.myers~inl. gov
~ ~~.
\(QQ
SECRETARY
CERTIFICATE OF SERVICE