20090506Kalich Direct.pdf

DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL FOR
REGULATORY & GOVERNENTAL AFFAIRS
AVISTA CORPORATION
P . O. BOX 3727
1411 EAST MISSION AVENUE
SPOKAE, WASHINGTON 99220-3727TELEPHONE: [phone]FACSIMILE: [phone]
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zaU9 ~Uy -6 AM 9: 47
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF A PETITION
FILED BY AVISTA CORPORATION
FOR AN ORDER DETERMINING THE
OWNERSHIP OF THE
ENVIRONMNTAL ATTRIBUTES
(URECS") ASSOCIATED WITH A
QUALIFYING FACILITY UPON
PURCHASE BY A UTILITY OF THE
ENERGY PRODUCED BY A
QUALIFYING FACILITY
CASE NO. AVU-E-09-04
DIRECT TESTIMONY
CLINT G. KALICH
FOR AVISTA CORPORATION
1
2
I. INTRODUCTION
Q.Please state your name, the name of your
3 employer, and your business address.
4
5
A.My name is Clint Kalich. I am employed by Avista
Corporation (UAvista" )at 1411 East Mission Avenue,
6 Spokane, Washington.
7
8
Q.In what capacity are you employed?
A.I am the Manager of Resource Planning & Power
9 Supply Analyses in Avista' s Energy Resources Department.
10 Q.Please state your educational background and
11 professional experience.
12 A.I graduated from Central Washington Uni versi ty in
13 1991 with a Bachelor of Science Degree in Business
14 Economics. Shortly after graduation, I accepted an analyst
15 position with Economic and Engineering Services, Inc. (now
16 EES Consulting, Inc.), a Northwest management-consulting
17 firm located in Bellevue, Washington.While employed by
18 EES, I worked primarily for municipalities, public utility
19 districts, and cooperatives in the area of electric utility
20 management.My specific areas of focus were economic
21 analyses of new resource development, rate case proceedings
22 involving the Bonneville Power Administration, integrated
23 (least-cost) resource planning, and demand-side management
24 program development.
Kalich, Direct 1
Avista Corporation
1 In late 1995,I left Economic and Engineering
2 Services, Inc. to join Tacoma Power in Tacoma, Washington.
3 i provided key analytical and policy support in the areas
4 of resource development, procurement, and optimization,
5 hydroelectric operations and re-licensing, unbundled power
6
7
supply rate-making,contract negotiations, and system
operations.I helped develop, and ultimately managed,
8 Tacoma Power's industrial market access program serving
9 one-quarter of the company's retail load.
10 In mid-2000 I joined Avista and accepted my current
11 posi tion assisting the company in resource analysis,
12
13
dispatch modeling,resource procurement,integrated
resource planning, and rate case proceedings.I have
14 previously provided testimony before this Commission both
15 in general rate cases and proceedings involving the Public
16 Utility Regulatory policies Act of 1978 (UpURPA").
17
18
Q.What is the purpose and scope of your testimony?
A.The purpose of my testimony is to support
19 Avista' s request that the Commission declare that the
20 environmental attributes (hereinafter referred to as
21 uRenewable Energy Credits" or URECs") associated with PURPA
22 projects be granted to the utilities that purchase the
23 energy. In my testimony I explain that current PURPA rates
24 in the State of Idaho (assuming that the utility does not
25 obtain ownership of the RECs when it purchases the energy
Kalich, Direct 2
Avista Corporation
1 generated by a wind Qualified Facility) substantially
2 exceed the cost of building and operating a wind plant.
3 This disparity equates to approximately $60 million in
4 excess costs over a 20-year PURPA contract term for a
5 single 10 aM proj ect. i
6
7 II. ECONOMICS OF PURPA RATES
8 Q.Why is Avista making this filing?
9 A.The Commission, in Case No. GNR-E-09-01, ordered
10 adjustments to various surrogate avoided resource (USAR")
11 assumptions, with the effect of greatly increasing the
12 avoided cost rates Avista will be required to pay PURPA
13 developers.For a 2010 PURPA project taking a 20-year
14 contract term, the PURPA rate increased from $71.27 to
15 $90.64 per MW.2 This rate is simply too high.using
16 Northwest Power and Conservation Council (UNPCC") wind
17 project cost estimates in Avista's revenue requirements
18 model demons tra tes that a PURPA-equivalent renewable
19 resource could be built for 32% less.Furthermore, where
20 Avista builds a PURPA-equivalent renewable resource, Avista
21 would also own all RECs associated with the project and its
1 The difference is calculated by reducing the cost to constrct and operate a wid project ($64/MWh),
based on NPCC costs for wid projects, by the expected value ofRECs ($15/MWh) to arve at a net
value of $49/MWh, and then comparg ths figue to the 2010 PUR A rate inclusive of the 7% wid
integration chage discount ($84/MWh). Avista's 2007 IR identified 300 MW of wid generation, the
equivalent of ten projects of ths size. Overpayment therefore would equal $600 millon were all of
Avista's needs met with Idaho PUR A resources, a possibility that is discussed later in ths testiony.2 Both values are before the 7% wind integration charge.
Kalich, Direct 3
Avista Corporation
1 customers would benefit from their value.As explained
2 below, assuming that the utility purchasing the energy from
3 a PURPA proj ect does not obtain ownership of the RECs with
4 the energy, the cost of a PURPA resource is 72% higher than
5 the cost associated with building a PURPA-equivalent
6 renewable resource.
7 Avista therefore requests that the Commission
8 recognize this significant discrepancy between the actual
9 cost of developing a renewable resource and the published
10 PURPA rate, and declare that ownership of all RECs
11 associated with PURPA projects be transferred to the
12 utility purchasing the energy from such projects.
13 Q.will transferring the RECS with the energy as
14 Avista proposes fully offset the differential between the
15 costs associated with current PURA rates and the costs
16 associated with Avista building and owning a similar
17 renewable resource?
18 A.No. Even transferring the RECs associated with a
19 PURPA project will not fully offset the differential
20 between Idaho's PURPA rates and the costs associated with
21 Avista building and owning a similar resource.The
22 transfer of RECs will, however, reduce the overpayment that
23 would otherwise occur.Please reference the following
24 chart.
25
Kalich, Direct 4
Avista Corporation
1 Chart 1 - PURPA Rate Comparison
Utilty Build vs. PURPA
20-year levelized cost (2010 delivery)
90
10
w/o RECs
$35.32
72%
80
70
_ 60.r
~ 50..11- 401;ov 30
20
o
Wind Cost Wind Cost No RECs PURPA (No RECs) PURPA With RECs
2
3 The chart shows that while the all-in project cost of
4 a new wind resource is approximately $64 per MW, the fact
5 that the RECs have a market value to the owner of
6 approximately $15/MW lowers the net uenergy" value to
7 approximately $49 per MW.3 This amount would be the PURPA-
8 equivalent avoided cost of a wind resource.Therefore,
9 when compared to the actual value of the produced energy,
10 the PURPA rate is 72% too high. 4 if RECs were assigned to
11 the utility, the differential between avoided cost and the
12 PURPA rate falls to 32%.
3 Recent market activity indicates that $l5/MWh is a reasonable forward price for RECs.
4 $84.30 is the present 2010 PURA rate of $90.64 less the 7% wind integration charge.
Kalich, Direct 5
Avista Corporation
1 Q.Please explain how Avista estimated a $64/MW
2 project cost for wind.
3 A.Avista derived a project cost estimate for wind
4 generation by inserting NPCC construction and operation
5 costs into its revenue requirements model.The NPCC
6 forecasts 2010 all-in (i.e., inclusive of AFUDC) wind
7 construction costs to be $2,017 per kilowatt, or about $101
8 million for a 50 MW wind proj ect.Fixed operations and
9 maintenance (UO&M") costs are estimated by the NPCC to be
10 $36. 98/kW-year.Variable O&M is estimated to be $l/MW.
11 Both O&M estimates are in 2008-year dollars and are
12 escalated per NPCC escalation assumptions in the revenue
13 requirements model. Based on these assumptions, the all-in
14 cost of a wind project without any federal tax subsidies is
15 $94. 51/MW levelized in 2010.
16 However,significant federal tax subsidies are
17 available for wind generation. Historically wind projects
18 have qualified for the 10-year Production Tax Credit
19 (UPTC") .This tax credit would lower the 2010 levelized
20 project cost to $77.1 7/MW.
21 The 2009 Federal Stimulus Bill provided an option
22 whereby instead of taking the PTC, a wind project could
23 instead elect to take a one-time upfront Investment Tax
24 Credit (UITC") equal to 30% of project costs.The basis
25 for tax purposes is reduced by 15% rather than the full 30%
Kalich, Direct 6
Avista Corporation
1 of the ITC. The ITC provides a much larger tax benefit to
2 Northwest wind proj ects that tend to have low capacity,
3 factors.Addi tionally, new renewable energy proj ects are
4 eligible for \\ 50% Bonus Depreciation"meaning tha t
5 depreciation can be accelerated to provide tax benefits to
6 the proj ect earlier than would otherwise be possible absent
7 the 50% Bonus Depreciation.Electing to take the ITC
8 instead of the PTC, combined with 50% Bonus Depreciation,
9 lowers the levelized cost of a proj ect, to a total of
10 $63.98/MW.The following chart details graphically the
11 impacts of the federal tax incentives.
12 Chart 2 - Impact of Federal Tax Credits on Wind
Impact of Tax Incentives on Wind Project Costs
2010 Delivery
100
90
80
70-Total..~60 Busbar
:?Cost..50"I Before-.¡40 Tax
II0 Benefis
U $94.5jMWh30
20
10
0
13
Kalich, Direct 7
Avista Corporation
1 The ITC and 50% Bonus Depreciation are available for
2 projects completed through 2012, therefore the price paid
3 to PURPA wind developers is overstated at least through
4 2012.
5 Q.How do current Idaho PURA rates compare with the
6 cost of building a new PURA-qualifying renewable resource?
7 A.In recent years, the vast majority of PURPA
8 proj ects under contract to Idaho utili ties have been
9 renewable energy resources.And, among the renewable
10 energy resources, a majority has been wind generation
11 projects. More than 2,500 MW of wind generation currently
12 exist in the Northwest; most of it has been built in the
13
14
past five years.The NPCC tracks these and other wind
generation projects.Its capital and operating cost
15 expectations for wind generation are similar to Avista' s.
16 Using NPCC assumptions, Avista estimates the total wind
17 generation cost for a wind resource entering service in
18 2010 is approximately $64 per MW levelized over 20 years,
19 two-thirds of the present PURPA rate of $90.64 per MW.
20 The disparity between these costs is increased if
21 utili ties do not receive the RECs when they purchase energy
22 generated by a PURPA project.
23 Accordingly, a wind resource will cost customers less
24 than an equivalent PURPA resource. Over a 20-year contract
25 term, the overpayment by Avista' s customers for each 10 aMW
Kalich, Direct 8
Avista Corporation
1 PURPA project could exceed $62 million; approximately $30
2 million on a present-value basis. 5
3
4
Q.Please explain why this differential is so large.
A.As discussed above, wind is a heavily subsidized
5 resource with certain tax benefits (e.g., PTC, ITC, and 50%
Bonus Depreciation)available to developers of wind6
7
8
9
resources.In addition, turbine prices appear to have
finally stopped rising.In fact there is some market
evidence that turbine prices might be falling.The NPCC
10 forecasts that projects coming online after 2009 will have
11 lower costs than for those entering service today.
12
13
Q.Please discuss the NPCC wind cost projections?
A.The NPCC forecasts that projects coming online
14 after 2009 will have lower costs than those entering
15 service today. The chart below provides a NPCC forecast of
16 capital costs for Northwest wind projects.
5 10 aM x 8,760 hours per year x $84.30 - $49) x 20 years = $62 milion
Kalich, Direct 9
Avista Corporation
1
2
2,200
2,100
2,000
1,900
1,800
1,700
1,600
1,500
1,400
1,300
1,200
1,100
1,000
Chart 3 - wind Project Costs
NPCC Projections and History
NPCCWind Project Cost Projection (2008$/kW)
r\/\/\/"-
I
I
I
1
-"---
.
,I I I ,,
o:i.\D "00 en 0 ..N M o:i.\D "00
0 0 0 0 0 0 ..................
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
N N N N N N N N N N N N N N N
Q.Are the tax benefits you discussed (the ITC,PTC
and 50%Bonus Depreciation)available to PURPA developers?
3
4
5
6 A.Yes.PURPA developers have access to the same
7 tax benefits as Avista.
8
9
10
Will these tax benefits continue?Q.
A.The ITC is available to any wind proj ect entering
service through 2012.Accordingly, contracts for power
11 beginning as late as 2013 (i.e., completed in late 2012 and
12 entering service in 2013 at 2013 PURPA rates) could benefit
13 from this credit.Addi tionally, the ITC extends out
14 through 2013 for non-wind renewable resources.
Kalich, Direct 10
Avista Corporation
1
2
The ITC also has the potential to be extended beyond
2012.With the exception of 2002, the government has
3 continued to extend tax benefits for renewable generation
4 since they were introduced in 1992.
5 Q.How would transferring the ownership of RECs
6 associated with PURPA resources affect the comparability of
7 PURPA resources with utility avoided costs?
8 A.As explained earlier in my testimony, and shown
9 in Chart 1, assignent of the RECs to the purchasing
10 utility would lower the differential between PURPA rates
11 and wind plant costs from 72% to 32%.
12 Q.Could RECs be worth more than the $15 per MW
13 over the term of a PURPA contract?
14
15
16
A.Yes.The value of RECs could increase as more
states,or the federal government,adopt renewable
portfolio standards.Inflation alone has the potential to
17 increase prices over time. Higher environmental attribute
18 values will push existing PURPA rates further out of line
19 with the actual costs of constructing and operating a wind
20 project that would have RECs associated with it.
21 Q.What has been the response from developers to the
22 new PURPA rates that went into effect in Order No. 30744?
23 A.After the new PURPA rates went into effect,
24 Avista received requests for five PURPA contracts-three in
25 one afternoon.Developers want to get their foot in the
Kalich, Direct 11
Avista Corporation
1 door while PURPA rates are high.To the extent that RECs
2 do not transfer to a utility paying for power under PURPA,
3 these developers also want to sell their RECs to further
4 increase profits.
5
6
7
III. A CHAGING ENVIRONMNT
Q.In 2004, the Commission decided against granting
8 a declaratory order to determine the ownership of RECs
9 associated with PURPA projects. Has anything changed since
10 2004 that should cause the Commission to grant Avista's
11 request?
12 A.Yes.In 2004 the Commission found that a
13 declaratory order should be based on existing or actual
14 facts, but that adequate facts were not present at the
15 time.Today such facts exist.Idaho PURPA rates have
16 increased, the value of RECs has substantially increased
17 and, as explained above, Avista is currently responding to
18 five requests for PURPA contracts.Absent Commission
19 action Avista' s customers will be harmed by paying too much
20 for energy produced by PURPA renewable resources,
21 especially wind resources.
22 Q.Please be more specific in terms of the changed
23 environment.
24 A.First, according to the Renewable Energy Policy
25 Proj ect (http://ww . repp. org!rps map. html) , all but 16 U. s.
Kalich, Direct 12
Avista Corporation
states (68% )now have renewable portfolio standards1
2
3
4
(URPS") .Many expect the federal government to enact an
RPS applicable to all states.As a resul t of the RPS
requirements,a robust REC market has emerged.
5 Irrespective of whether or not the utility "retires" the
6 RECs associated with a project, they have a substantial
7 marketable value from which customers can benefit.
8 Renewable resources that have REC value associated with
9 them make up the vast maj ori ty of Avista' s resource
10 acquisition plans for the next ten years .
11 Second, the value of RECs has increased dramatically.
12 In 2004, RECs were valued at approximately $2 per MW.
13 Today REC values are substantially higher, equating to as
14 much as $15 or more per MW.
15 Third, PURPA rates are substantially higher than they
16 were in 2004. In 2004, Idaho's PURPA rates were $53.56 per
17 MW for a 20-year levelized contract.Idaho's current
18 PURPA rate is $84.30 per MW (after discounting for the
19 wind integration charge) for a 20-year levelized contract.
20 Using the NPCC dataset on historical wind turbine prices, I
21 have updated the previous chart to include a comparison of
22 where rates were in 2004 relative to what wind development
23 costs were.As the graphic shows, back in 2004 the PURPA
24 rate was essentially on par with wind avoided costs, a much
25 different position than is before us today.
Kalich, Direct 13
Avista Corporation
1
2
3
4
90
80
70-60.c
3:50~..'V 40-..(I0 30u
20
10
0
5
6
7
Chart 4 - Wind Proj ect Costs
Comparison to PURPA Rates, 2004 and 2010
Utilty Build vs. PURPA
20-year levelized cost (2004 vs 2010 delivery)
Utilty 104 PURPA 104 Utilty Build 110 PURPA 110
Finally, Avista currently has five PURPA developers
requesting contracts.If each of these results in an
12
8 executed contract at the present rates, and assuming that
9 the RECs do not transfer to Avista with the energy,
10 Avista's customers could overpay by approximately $310
11 million over the contract lives of these five contracts. 6
6 Five 10 aM contracts at $62 million each above-cost. The $62 millon figue is documented earlier in
ths testiony.
Kalich, Direct 14
Avista corporation
1 Q.Is it necessary for developers to retain the RECs
2 as an incentive to develop PURPA projects?
3 A.No. Although that rationale may have made sense
4 in 2004 when PURPA rates were substantially lower relative
5 to the cost of building a wind resource and REC values were
6 relatively smaller, the rationale that developers needed to
7 retain the RECs in order to have an addi tional incentive
8 for developing PURPA projects does not hold given today's
9 substantially higher PURPA rates.
10 Q.IS Avista currently affected by the REC market?
11 A.Yes. Avista is currently marketing RECs from our
12 Spokane River projects, our Kettle Falls biomass project,
13 and our contracted interest in the Stateline wind Farm to
14 other states that already have requirements. The revenues
15 from these RECs are credited back to our customers,
16 including Idaho customers, to keep our retail rates lower
17 than what they otherwise would be.
18 Q.Are there other reasons that support assigning
19 PURA-generated RECs to the utility in Idaho?
20 A.Yes. As explained earlier, FERC has affirmed
21 that REC ownership is a state issue. FERC also has
22 declared that a state may decide that a PURPA sale of power
23 to a utility transfers ownership of state-created RECs.
24 Accordingly state commissions have the authority to make
25 this determination.
Kalich, Direct 15
Avista Corporation
1 As shown above, in Idaho and under current PURPA rates,
2 PURPA developers are compensated at a rate more than
3 sufficient to enable their success in constructing new
4 renewable energy proj ects and earning a sufficient return
5 on their investments. Even with the RECs assigned to the
6 utility, customers still are paying too much relative to
7 avoided costs. Allocating the RECs to PURPA developers
8 would unfairly enrich them at the expense of utility
9 ra tepayers .
10
11
12
iv. COMPARILITY
Q.Must PURA rates for wind precisely match what it
13 would cost to build a wind project?
14 A.Avista is not suggesting that PURPA rates be
15 exactly equal. This would be difficult given the dYnamics
16 of the marketplace in which proj ect construction occurs;
17 however, PURPA rates and actual avoided costs should be
18 relatively close since Avista and the developer would be
19 purchasing equipment and installation services in the same
20 marketplace. Further, in the case of wind, as much as 80%
21 of the total project cost is the wind turbines. Avista or
22 other project developers should have similar opportunities
23 to procure turbines.
Kalich, Direct 16
Avista Corporation
1
2
Q.Why do they need to be relatively close?
A.PURPA developers should be compensated at a rate
3 roughly comparable to Avista' s avoided cost. In other
4 words, the costs Avista would avoid by having the PURPA
5 project in its resource portfolio. Where Avista is
6 obligated to purchase PURPA project output at a cost
7 significantly higher than were it to construct its own
8 renewable resource, its customers are disadvantaged. It is
9 my understanding that such a result is not consistent with
10 the intent of PURPA which attempts to achieve comparability
11 to avoided costs.
12 Q.Does the federal governent provide guidance
13 here?
14 A.Yes. In Case No. IPC-E-04-2 the Commission cited
15 an order issued by FERC on October 1, 2003 order (105 FERC
16 9I 61,004), concluding that "...(PURPA)avoided costs were
17 intended to put the utility into the same position when
18 purchasing QF capacity and energy as if the utility
19 generated the energy itself or purchased the energy from
20 another source..."FERC also stated that the ultimate
21 determination of REC ownership falls to the states.
22 In the 1980s Avista constructed the Kettle Falls wood
23
24
waste-fired generating proj ect.It retains the RECs for
its cus tomers ' benef it.In 2004 Avista contracted for a
25 share of the Stateline Wind Farm, and Avista received the
Kalich, Direct 17
Avista Corporation
1 RECs for the benefits of its customers.It is unfair for
2 Avista' s customers to pay for the cost of a renewable
3 resource and not receive the benefit of the RECs.
4 Q.Please provide some background on Avista' s
5 Resource Acqui si tion Plans.
6 A.Avista's draft Preferred Resource Strategy from
7 its current IRP process shows that over the next 10 years
8 Avista expects to acquire substantial amounts of renewable
9 and conservation resources.In total, Avista estimates
10 that it will acquire 300 MW of wind, 35 MW of non-wind
11 renewables, and about 150 MW of conservation. The IRP does
12 not point to any additional gas-fired generation for more
13 than a decade. The Preferred Resource Strategy is based on
14 an analysis of cost, reliability (system capacity), risk,
15 system obligations, and legal obligations (e. g., federal
16 and state laws).
17 To implement its acquisition strategies,Avista
18 presently is pursuing a numer of renewable generation
19 proj ect options.In 2008, Avista acquired the development
20 rights for a 50 MW wind project in its service territory
21
22
near Reardan, Washington.Avista is also pursuing
development rights to other renewable energy proj ects.If
23 Avista develops wind resources itself, it will receive the
24 RECs along wi th the energy.
Kalich, Direct 18
Avista Corporation
1 Q.How are other jurisdictions addressing REC
2 values?
3 A.Avista has queried the various western states.
4 California and Wyoming have explicitly assigned PURPA RECs
5 to the purchasing utility. For California, the law affects
6 not only PURPA resources developed within the state, but
7 also resources developed outside its borders. Other states
8 have not ruled on this issue.
9 Q.How do Idaho PURPA rates compare to surrounding
10 states?
11 A.Idaho has by far the highest avoided cost rates
12 in the Northwest. In some cases the rate is nearly double
13 neighboring state rates. See the following chart.
14
Kalich, Direct 19
Avista corporation
1 Chart 5 - Northwest State PURPA Rates sumry
Wy
$482
UT
$46
2
3
1 NVbased on Mid.C Index, 200Saverage
2 WY assigns RECs to utility; their priæ is reduced by $15
per MWh for consistency with other states in this graphic
that do not obligate developers to provide their RECs
as a precondition ofa PURPAsale.
Were PURPA rates lower, the grant of RECs to the
4 developer might not be as significant.Developers would
5 receive a rate for their "non-green" power closer to the
6 energy value of their resource.But when rates rise to
7 $90.64 per MW ($84.30 when adjusted for wind integration)
8 and RECs provide another large revenue stream (perhaps an
9 additional $15/MW or more) the economics are skewed
10 greatly to the benefit of PURPA developers because the SAR
11 does not reflect the actual cost of those resources.
12
13
Q.The SAR does not have any REC values associated
with it.Why should Avista receive RECs from PURPA
14 projects when the SAR price is for a resource without RECs?
Kalich, Direct 20
Avista Corporation
1 A.The current Idaho SAR is based on a gas-fired
2 resource that does not generate any associated REC value.
3 wind proj ects are not equivalent to gas resources.
4 Q.How are wind resources different from gas-fired
5 resources?
6 A.Because wind resources do not provide significant
7 capacity, it is necessary to construct other resources to
8 meet system peak loads. Where a 30 MW wind generation
9 resource provides a 32% capacity factor, it is estimated to
10 provide only a 5% on-peak capacity contribution (1.5 MW)
11 according to the NPCC. Avis ta, in its resource plans,
12 assumes a zero on-peak contribution. It is therefore
13 necessary to install capacity resources to back wind up.
14 In other words, wind does not avoid the capacity investment
15 and, assuming the back-up resource is a gas-fired plant, it
16 would require the installation of approximately 8.1 MW of
17 this resource (10 aMW - 1.5 MW). At the SAR-assumed
18 capacity cost of $1,300 per kW, the added cost of this
19 capacity is approximately $10.5 million, or about $19 per
20 MW. Therefore an $84.30 wind PURPA price equates to $103
21 per MW for wind. See the following table.
Kalich, Direct 21
Avista Corporation
1 Table 1 - Wind project Supplemental Capacity
2 Cost Calculations
3
Li :.
1 Project Size2 Capacity Factor
3 Energy
4 Energy
5 On-Peak Contribution
6 On-Peak Contribution
7 Net Capaci ty Required
8 Capaci ty Cos t
9 Annual Capi tal Recovery Rate
10 Annual Capital Recovery Rate
11 Total Cost
~ !.
30.0 MW
32%
9.6 aM
84,096 MW
5.0%
1.50 MW
8.10 MW
1,313 $/kW
15%
1,595.3 $/kW-yr
18.97 $/MW
Soiirce/Math
NPCC NW Average
Line 1 x Line 2
Line 3 x 8,760 hours
NPCC Es t imate
Line 1 x Line 5
Line 3 - Line 6
IPUC Order 30738
Avista estimate
Line 7 x Line 8 x Line 9
Line 10 / Line 4 x 1,000
4 Q.Doesn' t the wind integration charge cover the
5 cost of capacity to back-up wind?
6 A.No. Wind integration costs are separate from and
7 in addition to the cost of providing capacity at times of
8 system peak.The wind integration charge does not account
9 for the fact that wind does not bring capacity that is
10 essential for meeting peak period loads, matching real-time
11 load variations, and providing contingency reserves (e. g. ,
12 regulation, spinning and non-spinning reserves) .
13 The wind integration charge covers the costs of
14 operating existing dispatchable resources at sub-optimal
15 levels to enable the absorption of wind's inherent
16 variability.
17 Q.If, hypothetically, Avista's 10-year resource
18 acquisition plans included a gas-fired resource as well as
19 wind renewable resources and conservation, would it be
20 reasonable to pay the full published PURA rate for PURPA
21 renewable generation?
Kalich, Direct 22
Avista Corporation
1 A.No, for two reasons.First, even were Avista
2 acquiring natural gas-fired generation it still would be
3 procuring wind resources.The paYfent for PURPA renewable
4 resource energy should be based on comparability to the
5 value produced by the resource that Avista is avoiding.
6 Because the company is acquiring wind resources, it makes
7 sense to value PURPA resources as if they will avoid wind
8 generation, not gas-fired generation.
9 Second, a PURPA developer selling wind to Avista will
10 not allow Avista to avoid building a gas-fired project. In
11 the not-so-distant past, Avista and the region acquired
resources to meet energy def ici ts .This is no longer the12
13
14
case.Avista's needs are driven equally by the need for
capaci ty and energy.In fact, Avista's IRP shows that its
15 capacity deficit occurs prior to its need for energy. This
16 means that an acquisition of wind will not displace, or
17 avoid, the construction of a gas-fired resource.
18 Finally, were Avista to build a wind resource today
19 with current federal incentives its expected costs would be
20 lower than the PURPA rate, as explained earlier in this
21 testimony. A 2010 PURPA contract would provide a levelized
22 payment to the developer of $84.30 per MW. In addition to
23 this payment the developer, absent an order in this
24 proceeding assigning ownership of RECs associated with a
25 PURPA project to the utility purchasing the energy from
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Avista Corporation
1 such proj ect, could reap another $15 per MW or more for
2 the environmental attributes of the plant through a sale to
3 a third party, bringing total revenues to $99 per MW or
4 more. This reflects a substantial marginal benefit when
5 comparing these revenues to the NPCC-based costs for wind
6 resources of approximately $64/MW.
7 Q.Are there other impacts of the PURPA rate being
8 too high, besides the higher price?
9 A.Yes.Avista is concerned that the new PURPA
10 rates will negatively affect its ability to acquire cost-
11 effective renewable resources in a competitive acquisition
12 process.A reasonable query is: would a developer
13 participate in a competitive process if that developer can
14 obtain a net 72% premium for its generation under PURPA?
15 Likely the answer is no.
16 Q.Are there projects in Idaho that might take
17 advantage of this market discrepancy?
18 Were just two present developers of larger Idaho wind
19 projects (Windland's 200 MW Cotterell project and RES-NA's
20 425 MW China Mountain project) to pursue this opportunity
21 and "put" their projects on Idaho utilities, and then
22 market the RECs separately, the annual impact on Idaho
23 customers could be more than $70 million above what the
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Avista Corporation
1 NPCC and Avista estimate wind generation costs to be. 7
2 Over 20 years the total overpayment would equate to $1. 4
3 billion.The PURPA rate therefore has the potential to
4 remove Avista' s ability to procure cost-effective new
5 renewable resources.A developer likely would not
6 participate in a competitive bidding process that would
7 yield a lower price.
8 Q.Does this conclude your pre-filed direct
9 testimony?
10 A.Yes, it does.
7 The projects could potentially qualify for published PUR A rates by splittg into groups of 10 aM
resources.
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Avista Corporation