20071005Comments.pdf

SCOTT WOODBURY
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
472 WEST WASHINGTON STREET
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
BAR NO. 1895
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I;);\HO PUBLIC
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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 IDAHO POWER
COMPANY'S PETITION TO INCREASE THE
PUBLISHED RATE ELIGIBILITY CAP FOR
WIND-POWERED SMALL POWER
PRODUCTION FACILITIES; AND
TO ELIMINATE THE 90%/110%
PERFORMANCE BAND FOR WIND-POWERED)
SMALL POWER PRODUCTION FACILITIES.
CASE NO. IPC-07-
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, submits
the following comments.
BACKGROUND
On February 6 2007 , Idaho Power Company (Idaho Power; Company) filed a Petition with
the Idaho Public Utilities Commission (Commission) proposing a $10.72 per MWh wind
integration adjustment or reduction to published avoided cost rates. In support of its proposal, the
STAFF COMMENTS OCTOBER 5, 2007
Company submitted its recently completed Wind Integration Study. The Company requested a
Commission Order:
1. Raising 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) from the current level of
100 kW to 10 aMW per month; and
2. Authorizing Idaho Power to purchase state-of-the-art wind forecasting services that will
provide the Company with forecasts of wind conditions in those geographic areas where the
Company s wind generation resources are located. It is Idaho Power s proposal that the Order
should further provide that wind-powered QFs will reimburse the Company for their share ofthe
cost of the wind forecasting service; and
3. Authorizing Idaho Power to require the inclusion of a Mechanical Availability
Guarantee (MAG) in all new contracts to purchase energy from wind-powered QFs; and
4. In conjunction with the Commission s approval of paragraphs 1 2 and 3 above, the
Company proposes to eliminate the requirement that the 90%/110% performance band be included
in new contracts for energy purchases from intermittent wind-powered QFs.
A Notice of Petition and Notice of Preliminary Procedure was issued in Case No.
IPC- E-07 - 3 on February 16, 2007. As a matter of preliminary procedure and prior to any
procedural scheduling by the Commission, Idaho Power on March 15 2007, hosted the first public
workshop in Case No. IPC-07-3. Pursuant to Notice, a second public workshop was held on June
, 2007.
Based on additional analysis conducted in response to suggestions made during the public
workshops, the Company recomputed its wind integration cost. In response to subsequent
production requests, Idaho Power proposed that a wind integration adjustment of $7.92 per MWh
be applied to its published avoided cost rates. (Reference Idaho Power response to Production
Request No.3 of Renewable Northwest Project and the NW Energy Coalition).
On July 31 and August 10, 2007 , Commission Staff sponsored joint settlement workshops in
Case Nos. IPC-07-3 (Idaho Power), PAC-07-7 (PacifiCorp), and A VU-07-2 (Avista) to
explore whether parties of record could agree to a common generic wind integration adjustment to
published rates. IDAP A 31.01.01.272-276. The parties were unable to reach settlement during
these workshops.
ST AFF COMMENTS OCTOBER 5, 2007
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; Idaho Power; and Idaho Windfarms, LLC. 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, Idaho Power hired EnerNex, arguably the leading
S. consulting firm in the area of wind integration studies, and Wind Logics, a leading consultant
in the area of wind simulation studies. These consultants provided valuable expertise and
experience that supplemented the work of Idaho Power 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 Idaho Power 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 ofthe 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
integration, however, are driven not so much by the costs of the dispatchable resource used for
STAFF COMMENTS OCTOBER 5, 2007
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 US. While
Staff does not believe that other studies are directly comparable to Idaho Power , A vista 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, recognizes 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." (Petition page 8). Staff agrees. Workshops held to review the
results of the Company s integration study 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 this case and the $5.04 per MWh proposed by PacifiCorp in Case No. P AC-07- 7 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-year 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.
STAFF COMMENTS OCTOBER 5 , 2007
Finally, utility practices will improve as more experience and confidence is gained with wind
generation. In fact, in response to production requests, 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 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
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
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.
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
STAFF COMMENTS OCTOBER 5, 2007
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 Idaho Power, seven percent of current published avoided cost rates is $4.37 for a 20-
year contract with a 2007 online date. At nine percent, the integration cost would be $5.62 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
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
STAFF COMMENTS OCTOBER 5 , 2007
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 typical20-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 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 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 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.
STAFF 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
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.
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
STAFF COMMENTS OCTOBER 5, 2007
likelihood, however, that wind integration technology and practices will improve over time. As
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, Idaho Power will convene an informal wind
integration working group which will meet at least two times during 2008 to discuss Idaho Power
wind integration study and new data related to wind integration costs. In addition, Idaho Power 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 of the utility s cost or difficulty in integrating it.
STAFF COMMENTS OCTOBER 5 , 2007
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
90/110-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
STAFF COMMENTS OCTOBER 5 , 2007
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 Idaho Power Settlement Stipulation containing the following:
An integration cost adjustment as shown below should be applied to the published avoided
cost rates of Idaho Power for all intermittent PURP A resources, subject to a cap of $6.50 per
MWh.
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
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, where shown to be cost effective, 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 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
STAFF COMMENTS OCTOBER 5 , 2007
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
-1J1h
day of October 2007.
~b).
co t Woodbury
Deputy Attorney General
Technical Staff: Rick Sterling
Randy Lobb
i:umisc:comments/ipceO7.3swrps
ST AFF 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. IPC-07-, BY MAILING A COpy THEREOF, POSTAGE PREPAID, TO
THE FOLLOWING:
BARTON L KLINE
MONICA B MOEN
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
MAIL: bkline~idahopower.com
mmoen~idahopower.com
DR. DON READING
6070 HILL ROAD
BOISE ID 83703
MAIL: dreading~mindspring.com
NATALIE McINTIRE
RENEWABLE NORTHWEST PROJECT
917 SW OAK ST STE 303
PORTLAND OR 97205
BRIAN DICKMAN
ROCKY MOUNTAIN POWER
201 S MAIN ST SUITE 2300
SALT LAKE CITY UT 84111
MAIL: brian.dickman~pacificorp.com
ROBERT MELLIS
4 NICKERSON
SUITE 301
SEATTLE WA 98109
MAIL: rellis~rl-en.com
DEAN J. MILLER
McDEVITT & MILER LLP
PO BOX 2564
BOISE, ID 83701-2564
MAIL: ioe~mcdevitt-miller.com
PETER J RICHARDSON
RICHARDSON & O'LEARY PLLC
515 N 27TH STREET
PO BOX 7218
BOISE ID 83702
MAIL: peter~richardsonandoleary.com
WILLIAM M EDDIE
ADVOCATES FOR THE WEST
610 SW ALDER ST STE 910
PORTLAND OR 97205
MAIL: beddie~advocateswest.org
DEAN BROCKBANK
ROCKY MOUNTAIN POWER
201 S MAIN ST SUITE 2300
SALT LAKE CITY UT 84111
MAIL: dean.brockbank~pacificorp.com
RIDGELINE ENERGY LLC
C/O RICH RA YHILL
720 W IDAHO ST. SUITE 39
BOISE ID 83702
MAIL: rrayhill~rl-en.com
GLENN IKEMOTO
IDAHO WINDF ARMS LLC
672 BLAIR AVENUE
PIEDMONT CA 94611
MAIL: glenni~pacbel1.net
RONALD K ARRINGTON
ASSOCIATE CHIEF COUNSEL
JOHN DEERE RENEW ABLES LLC
PO BOX 6600
JOHNSTON IA 50131
CERTIFICATE OF SERVICE
R. BLAIR STRONG
JERRY K. BOYD
PAINE HAMBLEN LLP
717 W SPRAGUE, SUITE 1200
SPOKANE W A 99220
MAIL: r.blair.strong~painehamblen.com
KEN MILLER
CLEAN ENERGY PROGRAM DIRECTOR
SNAKE RIVER ALLIANCE
PO BOX 1731
BOISE ID 83701
MAIL: kmiller~snakeri veralliance.org
BRIAN D JACKSON
PRESIDENT
RENAISSANCE ENGINEERING
& DESIGN PLLC
2792 DESERT WIND RD
OASIS ID 83647-5020
MAIL: brian~c1ever-ideas.com
GARY SEIFERT PE
KURT MYERS PE
INL BIOFUELS & RENEW ABLE ENERGY
TECHNOLOGIES
2525 S FREMONT AVE
PO BOX 1625/ MS 3810
IDAHO FALLS ID 83415-3810
MAIL: gary.seifert~in1.gov
kurt.myers~in1. gov
MICHAEL G ANDREA
STAFF ATTORNEY
A VISTA CORPORATION
1411 EMISSION AVE, MSC-
SPOKANE W A 99202
MAIL: michae1. andrea(Ci),avistacofP .com
GERALD FLEISCHMAN
11535 W. HAZELDALE CT
BOISE ID 83713
MAIL: gfleisch986~hotmai1.com
M J HUMPHRIES
BLUE RIBBON ENERGY LLC
2630 CENTRAL AVE
IDAHO FALLS ID 83406
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