20120504Sterling Direct.pdf

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE COMMISSION'S )
REVIEW OF PURPA QF CONTRACT ) CASE NO. GNR-E-11-03
PROVISIONS INCLUDING THE SURROGATE )
AVOIDED RESOURCE (SAR) AND )
INTEGRATED RESOURCE PLANNING (IRP) )
METHODOLOGIES FOR CALCULATING )
PUBLISHED AVOIDED COAT RATES. )
DIRECT TESTIMONY OF RICK STERLING
IDAHO PUBLIC UTILITIES COMMISSION
MAY 4, 2012
i Q. Please state your name and business address for
2 the record.
3 A. My name is Rick Sterling. My business address
4 is 472 West Washington Street, Boise, Idaho.
5 Q. By whom are you employed and in what capacity?
6 A. I am employed by the Idaho Public Utilities
7 Commission as the Engineering Supervisor.
8 Q. What is your educational and professional
9 background?
10 A. I received a Bachelor of Science degree in
11 Civil Engineering from the University of Idaho in 1981
12 and a Master of Science degree in Civil Engineering from
13 the University of Idaho in 1983. I worked for the Energy
14 Division of the Idaho Department of Water Resources from
15 1983 to 1994. My work focused primarily on development
16 of renewable energy resources, and also on agricultural
17 energy conservation. In 1988, I received my Idaho
18 license as a registered professional Civil Engineer. I
19 began working at the Idaho Public Utilities Commission in
20 1994. My duties at the Commission include analysis of a
21 wide variety of electric, water, and gas utility
22 applications. I have been the lead Staff person on all
23 PTJRPA..related matters that have come before the
24 Commission since 1994. I am also responsible for
25 supervising the work of three engineers and four utility
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analysts.
2 Q. What is the purpose of your testimony in this
3 proceeding?
4 A. The purpose of my testimony is to discuss the
5 proposals of Idaho Power, PacifiCorp, and Avista made
6 pursuant to Order Nos. 32352 and 32388. These proposals
7 relate to the determination of avoided cost rates for
8 Qualifying Facilities (QF5) under the Public Regulatory
9 Policies Act of 1978 (PURPA) . More specifically, I will
io discuss my position on changes to both the Surrogate
ii Avoided Resource (SAR) methodology and the Integrated
12 Resource Plan (IRP) methodology as proposed by each of
13 the utilities. I will also address other issues raised
14 in this proceeding, including maximum contract length, QF
is contracting procedures and rules, curtailment rules, and
16 ownership of Renewable Energy Credits (RECS).
17 Summary of Recommendations
18 Q. Please summarize your recommendations.
19 A. My testimony discusses and recommends the
20 following:
21 1. That the Commission retain the use of the
22 SAR methodology for computing avoided cost rates for wind
23 and solar QFs 100 kW and smaller (nameplate capacity) and
24 for all other resource types 10 aMW and smaller;
25 2. That the Commission order the fuel price
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i forecast published annually by the U.S. Department of
2 Energy, Energy Information Administration in its Annual
3 Energy Outlook to be used to update published avoided
4 cost rates on July 1 of each year;
5 3. That the Commission adopt other changes to
6 the SAR methodology as discussed by Staff witness Dr.
7 Cathleen McHugh;
8 4. That the utilities implement both the SAR
9 methodology and the IRP methodology in such a way as to
10 not include any value for QF capacity provided in years
11 when the utility is in a surplus position;
12 5. That avoided cost rates computed under
13 both the SAR and IRP methodologies be reduced during
14 surplus years to account for costs associated with
15 transmission wheeling and losses;
16 6. That a simple cycle combustion turbine
17 (SCCT) be used as the basis for computing capacity value
18 under the IRP methodology for all resource types;
19 7. That the utilities be permitted to update
20 fuel price forecasts, load forecasts, and long-term
21 contract commitments (including QF contracts) between
22 biennial IRP filings for the purposes of computing
23 avoided Costs under the IRP methodology,
24 8. That maximum contract length be reduced to
25 five years for contracts containing rates computed under
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the IRP methodology;
2 9. That all three utilities be directed to
3 submit tariffs similar to PacifiCorp's proposed Schedule
4 38 outlining QF contracting procedures and rules;
5 10. That the rates contained in PURPA
6 contracts not be locked-in more than five years prior to
7 the scheduled operation date of the QF;
8 11. That the proposed curtailment tariff
9 (Schedule 74) proposed by Idaho Power be approved; and
10 12. That the Commission order that ownership
11 of Renewable Energy Credits (REC5) be assigned to the
12 utility.
13 Q. First, as a preliminary matter, do you believe
14 that there are changes that need to be made in the way in
15 which PURPA is being implemented in Idaho?
16 A. Yes, of course. I think that the utilities
17 have done a good job in their testimony in this
18 proceeding as well as in testimony in earlier phases of
19 this proceeding pointing out some of the problems with
20 the way PtJRPA is being implemented and the serious
21 consequences that have resulted. I am convinced that the
22 problems they discuss are real and that the consequences
23 are serious. In my opinion, the single biggest problem
24 with the current avoided cost methodology is that it
25 fails to account for whether a utility actually needs new
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i generation.
2 Q. Do you believe that the problems that have been
3 previously identified exist for all three utilities?
4 A. Yes, although clearly the consequences are most
5 severe for Idaho Power because it has experienced so much
6 more PURPA development in its service territory than the
7 other utilities. Nonetheless, despite the impact being
8 most severe for Idaho Power, I believe that some of the
9 problems that have been identified exist for all of the
10 utilities. Consequently, I propose that if the
11 Commission decides to make changes to avoided cost
12 computation methodologies or to other policies related to
13 QFs, that those changes and policies apply to all three
14 utilities unless there are clear reasons for utility-
15 specific policies.
16 SR Methodology
17 Q. Idaho Power has proposed that the SAR
18 methodology, which is currently used to compute
19 "published" avoided cost rates, be abandoned in favor of
20 using the IRP methodology for "standard" wind, solar,
21 baseload, and canal drop hydro facilities. Do you agree
22 with Idaho Power's proposal to abandon the SAR
23 methodology for small projects?
24 A. No, I do not. While I agree with Idaho Power
25 that the IRP methodology holds some advantages, even for
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i computing standard rates for small projects, I do not
2 believe that the advantages are great enough to warrant
3 abandonment of the SAR methodology entirely. The SAR
4 methodology has been employed in Idaho for computing
5 avoided cost rates since PURPA was first implemented.
6 Although it has been necessary to occasionally modify the
7 method and while it requires some vigilance to ensure
8 input variables and price assumptions are kept updated,
9 the method has generally proved satisfactory. Indeed,
10 the vast majority of PURPA contracts approved to date
11 contain rates computed using the methodology. Project
12 developers have shown a clear preference for the method,
13 admittedly mostly due to its ability to produce favorable
14 rates, but also, I believe, because of its transparency.
15 As long as application of the SAR method is restricted to
16 only relatively small projects, I believe it can continue
17 to be successfully used. Furthermore, if fuel prices and
18 other assumptions used in the model are kept updated,
19 then the avoided cost rates calculated using the
20 methodology should be reasonably close to the rates
21 calculated under the IRP methodology. The SAR
22 methodology is intended to model the cost of a CCCT,
23 while CCCT5 are frequently the units setting the market
24 clearing prices under the IRP methodology. The rates
25 under each methodology will never match exactly, but they
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i should be reasonably close.
2 100 kW Cap for Wind & Solar Under SPJR Methodology
3 Q. Existing rules require that eligibility for
4 avoided cost rates computed using the SAR methodology be
5 limited to facilities no larger than 100 kW (nameplate
6 capacity) for wind and solar projects and 10 aMW for all
7 other resource types. Do you believe that these
8 eligibility limits should be retained?
9 A. Yes, I do. The 100 kW limit for wind and solar
10 facilities was implemented on a temporary basis,
11 beginning on December 14, 2010, in Case No. GNR-E-10-04
12 (See Order No. 32176) primarily to address the
13 disaggregation issue related to wind and solar
14 facilities. The ability of these resource types to
15 disaggregate still exists as long as the financial
16 incentive remains. The specific size limit of 100 kW was
17 selected because FERC rules implementing PURPA require
18 that standard rates be established for qualifying
19 facilities with a design capacity of 100 kW or less.
20 (See 18 CFR 292.304(c)). The 10 aMW limit has been in
21 place for many years for other resource types, and I see
22 no compelling reason to change it at this time, provided
23 fuel prices are updated. Both Avista and PacifiCorp have
24 also proposed that the SAP. method and its current
25 eligibility limits be retained.
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1 Q. If the SAR method is retained for small QFs,
2 are there modifications you think should be made to the
3 methodology?
4 A. Yes, there are a few. First, Staff believes
5 that the fuel price forecast used in the model should be
6 updated annually using DOE EIA Annual Energy Outlook. In
7 addition, we believe that the model should be modified to
8 account for utilities' surplus periods. Staff witness
9 Dr. Cathleen McHugh discusses Staff's proposed
io modifications to the SAR methodology in more detail in
11 her testimony.
12 IRP Methodology
13 Q. Idaho Power proposes that the IRP methodology
14 be used to compute avoided cost rates for QF5 of all
15 sizes, with "standard" wind, solar, baseload and canal
16 drop facilities used as the basis for rates for small
17 QFs. Do you agree with this proposal?
18 A. No, as I explained previously, I believe that
19 the SAR method should continue to be used for solar and
20 wind facilities up to 100 kW nameplate and for all other
21 project types up to 10 aMW.
22 Avoided Cost of Energy
23 Q. Idaho Power, in the testimony of Karl
24 Bokenkamp, proposes to use the AURORA model to determine
25 the highest displaceable incremental cost being incurred
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during each hour of the QF's proposed contract term. Do
2 you agree with Idaho Power's approach?
3 A. Yes, I do.
4 Q. Idaho Power witness Bokenkamp, at page 13 of
5 his direct testimony, explains how the Company proposes
6 to treat long-term firm purchases. He explains that "if
7 the firm purchase is resold at market price and the QF
8 generation is accepted, then the incremental cost avoided
9 is the net proceeds from the resale of the firm purchase
10 after any transaction-related costs such as transmission
costs, losses, etc." However, to simplify the analysis,
12 Idaho Power proposes to disregard the transaction-related
13 costs and losses. Do you think this is appropriate?
14 A. No, I do not. Although it would simplify the
15 analysis, transaction-related costs and losses are real
16 and could be significant in many cases; therefore, they
17 should rightfully not be borne by Idaho Power and its
18 ratepayers. In a production request, Staff asked Idaho
19 Power to estimate these costs. Idaho Power responded by
20 stating that transaction costs associated with reselling
21 any of Idaho Power's longer-term firm purchases will
22 depend on the location and timing of the purchases, and
23 on actual market conditions. The Company identifies
24 several alternatives to consider: (1) resell at the point
25 of purchase, (2) deliver the purchase to Idaho Power's
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a. system and then resell it at Idaho Power's border,
2 (3) wheel the energy from Idaho Power's border to a more
3 liquid market, or (4) wheel from the point of purchase to
a more liquid market. (See Idaho Power Company's
5 Response to Staff Request No. 18). In all except the
6 first scenario, Idaho Power admits that it would incur
7 transmission costs and losses. As a reasonable estimate,
8 I would recommend that transmission costs be based on
9 moving surplus energy from Idaho Power's system to the
10 Mid-C market. Under this assumption, transmission costs
11 would be $3 per MWh and losses would be approximately
12 $1.50 per MWh.
13 Q. Under the method used by Idaho Power for
14 computing the avoided cost of energy, an assumption is
15 made that in order to be displaceable, a resource has to
16 be online and capable of staying online and further
17 reducing its output. Therefore, under Idaho Power's
18 method, not all resources are entirely displaceable. Do
19 you agree with the assumptions and methods proposed by
20 Idaho Power?
21 A. Yes, I do. I believe that Idaho Power has
22 properly focused on the incremental costs that the
23 utility would incur as the basis for determining avoided
24 costs. The focus on incremental cost appears entirely
25 consistent with the definition of avoided cost as
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1 contained in 18 C.F.R. 292.101(b) (6) . Furthermore, I
2 believe that the IRP methodology as proposed by Idaho
3 Power conforms more closely with FERC's definition of
4 avoided cost than the way in which Idaho Power has
5 employed the methodology in the past.
6 Q. Has Staff reviewed in detail the manner in
7 which Idaho Power proposes to calculate the avoided cost
8 of energy? If so, did Staff's review identify any errors
9 in Idaho Power's computations of energy value?
10 A. Yes, Staff thoroughly reviewed Idaho Power's
ii methods for calculating the avoided cost of energy. In
12 our review, we identified a couple of errors. First, in
13 the energy component figures provided in the Company's
14 direct testimony and exhibits, the Company used an
15 outdated natural gas price forecast. The Company has
16 used its updated forecast to recompute the energy values
17 and has incorporated the results of that recomputation in
18 results provided in Idaho Power's Supplemental Response
19 to Staff Production Request No. 2. The effect of using a
20 more updated gas forecast is a small decrease in the
21 proposed avoided cost rates. Second, Staff discovered
22 that the displaceable incremental costs for various
23 thermal units were not being properly escalated in Idaho
24 Power's analysis to compute the avoided cost of energy.
25 Idaho Power corrected this error in the results provided
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in Supplemental Response to Staff Production Request
2 No. 2. The effect of this correction was a small
3 increase in the avoided cost of energy. The combined
4 effect of both corrections, one positive and the other
5 negative was only a small change to the avoided cost
6 rates.
7 In our review, Staff also identified instances
8 in which it appeared that Idaho Power was operating one
9 of its own resources during hours when prices in the
10 market were lower. However, further analysis seems to
11 indicate that Idaho Power was likely forced to operate
12 its own higher cost resources in these hours because of
13 either transmission constraints or because of minimum up
14 times of its thermal resources. Consequently, Staff is
15 satisfied that the analysis performed by Idaho Power is
16 correct.
17 Q. Idaho Power's testimony describes its proposed
18 methodology for computing the avoided cost of energy as
19 being different than the currently approved methodology.
20 Are the two methodologies actually different, and if so,
21 are the differences acceptable?
22 A. Yes, the methodologies are different. However,
23 I believe that the differences are reasonable. One of
24 the primary reasons for the differences is because under
25 the currently approved methodology, there has always been
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a presumption that the dispatch of existing resources
2 would change, or alternatively, that a new resource would
3 be displaced or deferred. In most cases, however, new QF
4 resources are too small to affect dispatch or resource
5 decisions in AURORA. Therefore, unless some modification
6 is made to the currently-approved methodology, it is not
7 being implemented in the way in which it was intended.
8 Consequently, I believe that the methodology as proposed
9 by Idaho Power is acceptable, and as I stated previously,
10 an improvement over the currently-accepted methodology.
11 Q. One of the key underlying assumptions made by
12 Idaho Power in its modified methodology for computing the
13 avoided cost of energy is that QF generation is not used
14 to make market sales at AURORA-generated market clearing
15 prices. Do you agree with this assumption?
16 A. Yes, I do. I think this assumption is
17 fundamental in order to comply with PURPA as it was
18 intended. Utilities should not be required to make
19 purchases under PURPA in a particular hour if by doing so
20 it is concurrently required to make an equivalent and
21 offsetting sale in order to balance its system.
22 Avoided Cost of Capacity
23 Q. The utilities propose that the value of
24 capacity not be included in avoided cost rates during
25 periods when the utility is surplus. Do you agree with
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1 this approach?
2 A. Yes, I do. I believe that the failure to
3 account for the utilities' need for new generation is one
4 of the most serious problems that needs to be addressed
5 in this case. It is well established that utilities must
6 honor their obligation under PURPA to purchase power
7 offered by QFs. However, utilities are not required, in
8 fact, they are not permitted, to pay more than their
9 avoided cost for capacity and energy provided by a QF.
10 The proper mechanism for accounting for utility need is
11 not to relieve utilities of their obligation to purchase,
12 but instead to establish prices for capacity and energy
13 that properly recognize the utilities' need, or lack of
14 need, for capacity and energy. By not paying for
15 capacity during surplus periods, utilities would be
16 paying what amounts to a more accurate reflection of a
17 true avoided cost.
18 Q. Is a utility's need for capacity and energy
19 taken into account under the IRP methodology?
20 A. Yes, I believe that it is under the IRP methods
21 proposed by the utilities in this case. Capacity and
22 energy deficit positions are recognized by the IRP models
23 used by the utilities, and appropriate resources are
24 added at appropriate times in order to satisfy those
25 deficits. If a utility does not have a need for a new
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i capacity or energy resource, then one is not added until
2 it is needed. Energy values computed by the models are
3 based on economic dispatch of all resources in the
4 utility's portfolio at any given time, subject to the
5 operating constraints and requirements of the various
6 resources.
7 All three of the utilities use methods to
8 determine capacity values under the IRP methodology
9 outside of using their dispatch models (AURORA, GRID, and
10 PRiSM). In the methods used by each utility, none assign
11 capacity value to QFs in years when the utility is in a
12 surplus condition.
13 Q. Didn't the SAR methodology, at one time attempt
14 to account for a utility's surplus period in computing
15 avoided cost rates?
16 A. Yes, it did, from the time PURPA was
17 implemented in Idaho up until 2002, in Case No.
18 GNR-E--02-01, Order No. 29124. At that time the
19 Commission abandoned consideration of utilities' surplus
20 periods in the computation of avoided cost rates for a
21 variety of reasons as discussed in the direct testimony
22 of Avista witness Clint Kalich. While all of the reasons
23 for abandoning consideration of surplus periods made good
24 sense at the time, and while some of the concerns may
25 still be valid today, I believe that the need for
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i consideration of surplus periods now outweighs those
2 concerns. Any difficulty that may exist in considering
3 surplus periods can be overcome by careful definition of
4 the term "surplus." I believe that Mr. Kalich has
5 discussed an acceptable method for determining when a
6 utility is energy or capacity surplus based on its summer
7 and winter load-resource balance.
8 SCCT vs. CCCT as the Basis for Determining Capacity Value
9 Q. Idaho Power proposes that a simple cycle
10 combustion turbine (SCCT) be used as the basis for
11 computing the capacity cost component of avoided cost
12 rates. Do you agree with this approach?
13 A. Yes, I do. I made a similar recommendation in
14 Staff's comments in Case Nos. IPC-E-11-10 (Interconnect
15 Solar), and IPC-E-11-26 (High Mesa Energy). Idaho Power,
16 in both of these cases, calculated capacity value using a
17 CCCT rather than an SCCT. Because of the relatively low
18 expected capacity factor of these projects, the
19 intermittent nature of their generation, and the fact
20 that they cannot be expected to deliver capacity with
21 complete certainty during the time of the utility's
22 system peak, I felt that a SCCT would be more appropriate
23 than a CCCT for computing capacity value.
24 Q. Do you agree with Idaho Power's proposal to use
25 an SCCT for computing capacity value for all resource
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i types regardless of their operating characteristics?
2 A. Yes, I do. SCCTs are generally added to
3 utilities' resource portfolios to satisfy capacity-only
4 needs, and are usually the least cost capacity resource
5 available. Therefore, the cost of an SCCT can reasonably
6 be considered a capacity-only cost. Utilities that add
7 CCCTs to their portfolio do so because they have a need
8 for both capacity and energy, thus the cost of a CCCT can
9 be considered both a capacity and energy cost. CCCT5,
io because they are more efficient, generate energy at a
11 lower variable cost than SCCT5, but the tradeoff is that
12 they are more costly to construct.
13 Under the methodology as proposed by the
14 utilities, capacity and energy values are being
15 calculated independently. Therefore, I maintain that the
16 proper resource to use as the basis for computing
17 capacity value is the lowest cost resource that could be
18 added to provide capacity equivalent to what would
19 otherwise be provided by the QF. I believe that using a
20 SCCT is probably most appropriate because it represents
21 the lowest cost, nearly capacity-only resource.
22 Q. PacifiCorp proposes that a deferrable CCCT,
23 rather than an SCCT, be used as the basis for computing
24 capacity cost. Do you agree with this approach?
25 A. Although the Company's rationale is sound
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i because CCCT capacity is, in fact, what might presently
2 be deferred by the addition of a QF, I still believe that
3 basing capacity value on the cost of an SCCT is more
4 appropriate for the reasons stated previously.
5 Peak Hours for Analyzing System Peak
6 Q. In evaluating a potential QFs contribution to
7 meeting the utility's system peak for purposes of
8 computing capacity value, Idaho Power proposes to
9 consider the hours between 3:00 pm and 7:00 pm for all
10 days in July. Pac±fiCorp proposes to consider the top
100 summer peak hours for the years 2007-2010. Do you
12 believe either proposal is acceptable?
13 A. I believe there is room for improvement. I am
14 not particularly concerned that each utility define its
15 peak hours in precisely the same way because each
16 utility's peak may occur at different times of the year
17 and because the shape of the peak may differ between
18 utilities. However, I do believe that it is important to
19 consider hours symmetrically around the peak. For
20 example, Idaho Power's approach of considering specific
21 hours in the entire month of July may be too arbitrary.
22 It could be that hours in the third or fourth weeks of
23 June experience higher peak loads than corresponding
24 weeks in late July. Consequently, I would recommend that
25 Idaho Power revise its approach to better identify the
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top peak summer hours independent of whether they occur
2 in June or July.
3 Comparison of Results
4 Q. Have you prepared a comparison of the avoided
5 cost rates computed by each of the utilities under the
6 IRP methodology?
7 A. Yes, I have. Exhibit No. 304 shows the costs
8 of energy and capacity computed by each of the utilities
9 using the IRP methodology for four sample project types.
10 Each sample project type was chosen in order to
11 illustrate the range of difference in rates for projects
12 with very different generation characteristics. The base
13 load project type would be typical of a project with a
14 very consistent year-round and diurnal generation
15 pattern, such as a geothermal or biogas facility. The
16 canal drop project type would be typical of most projects
17 located on irrigation systems, with steady seasonal
18 generation, but no generation in the non-irrigation
19 season. The fixed photovoltaic solar system would be
20 typical of a facility located in southern Idaho oriented
21 to maximize on-peak generation. The wind project is
22 intended to closely represent the same type of facility
23 that has commonly been installed in southern Idaho in
24 recent years. In making their calculations, each utility
25 made exactly the same assumptions of the annual
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i generation amounts and timing for each respective sample
2 resource type. It should be pointed out that the results
3 shown in Exhibit No. 304 are preliminary and reflect
4 Staff's understanding of the utilities' results as of the
5 time of filing of this testimony. The calculated rates
6 could change during the course of this case due to
7 corrections, revised fuel forecasts, and changes in long-
8 term contract commitments.
9 Q. What observations can you make from the results
10 shown in Exhibit No. 304?
ii A. One observation is that the avoided cost of
12 energy is quite similar for each of the three utilities.
13 It is also similar for each of the resource types.
14 A second observation is that the differences in
is rates, both between utilities and between resource types
16 is mostly attributable to differences in the avoided cost
17 of capacity. For example, the avoided cost of capacity
18 is extremely low for the wind project, for all three
19 utilities. This is because of the low probability that
20 wind will be able to provide capacity during the time of
21 any of the utilities' peak load hours.
22 A third observation is that neither a canal
23 drop project nor a fixed pv solar project provides much,
24 if any, valuable capacity for Avista. This is because
25 Avista is a winter peaking utility, and a canal drop
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facility would not be operating in the winter and a solar
2 facility would provide only minimal capacity during
3 winter evening hours when Avista's peak occurs.
4 A fourth observation is that the rates for
5 canal drop hydro, at least for Idaho Power and
6 PacifiCorp, are higher than the rates for the other
7 resource types. This again is primarily due to the
8 capacity component of the rate being relatively high.
9 The capacity component is high for canal drop hydro for
10 two reasons. First, the capacity is provided during peak
11 summer hours when it is most valuable to the utility.
12 Second, the capacity value is spread over fewer kWhs than
13 for other resource types because a canal drop hydro
14 project would only be operating during the irrigation
15 season.
16 Q. Are the differences in the results for each
17 utility surprising to you?
18 A. No, I expected that the results would be
19 different for each utility because each utility's
20 circumstances are different.
21 Q. Are the differences in the results for each
22 resource type surprising to you?
23 A. No. Each resource type is quite different in
24 its generating characteristics; consequently, it is
25 reasonable to expect that each would provide different
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1 value, particularly capacity value. Wind resources, for
2 example, have a very low probability of providing
3 capacity during the utilities peak load hours, while
4 base load types of resources have a high probability.
5 Therefore, the capacity component of the avoided cost
6 rate should reflect these differences in value.
7 IRP Assumption Updates
8 Q. The IRP methodology relies on numerous
9 assumptions from the IRP such as fuel price forecasts,
10 load forecasts, resource costs, load-resource balances,
11 and composition of preferred portfolios. Do you believe
12 that the assumptions contained in each utility's last
13 acknowledged IRP should be locked-in for purposes of
14 calculating avoided cost rates, or should updates to some
15 of these assumptions be permitted in the interim between
16 IRP5?
17 A. I believe that it is appropriate for some
18 assumptions to be updated and for others to remain fixed.
19 In my opinion, the items that should be allowed to be
20 updated are fuel price forecasts, load forecasts, and new
21 contract obligations (including new QF contracts)
22 Fuel price forecasts should be updated
23 annually. I suggest that the timing of the updates
24 coincide with whatever schedule is adopted for fuel price
25 updates made under the SAR methodology Unlike the
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a. recommendation for use of the DOE/EIA Annual Energy
2 Outlook forecast for the SAR methodology, however, I
3 believe that utilities should be permitted to use the
4 same forecasts and sources (or combinations of sources)
5 as they use in their IRPs for use with the IRP
6 methodology. Although the utilities generally update
7 their fuel price forecasts more frequently than annually,
8 I believe that a more frequent update would complicate
9 contract negotiations if fuel prices are changed too
io frequently.
11 Load forecasts should be updated no more
12 frequently than annually. New contract commitments
13 should be updated whenever a new commitment is made,
14 either for a long-term purchase or a sale. By long-term,
15 I am referring to any commitment made at least a year in
16 advance or one extending for a year or more in duration.
17 Short-term commitments, because they are usually made on
18 short notice and can frequently change, should not be
19 considered in the utility's load-resource balance used
20 for computing avoided cost rates.
21 New PURPA contracts should be included in the
22 load resource balance. However, I believe that they
23 should only be incorporated once a contract has been
24 signed by the QF and submitted to the utility for
25 signature. The mere indication of interest or request
CASE NO. GNR-E-11-03 STERLING, R (Di) 23
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for a contract is too speculative to justify
2 incorporating a change in the utility's load-resource
3 balance. PURPA contracts that are terminated, expire, or
4 that have approved modifications of their online dates
5 should also be immediately considered in the load
6 resource balance.
7 Q. Idaho Power proposes that a "queuing" process
8 be established such that upon its receipt of a written
9 request from a QF for contract pricing, the QF is
io designated as "queued" and therefore considered in
11 calculating avoided cost rates. Do you agree with this
12 proposal?
13 A. No, not entirely. As I explained above, I
14 believe that new QFs should not be considered in avoided
15 cost rate calculations until a contract has actually been
16 signed. Technically, Idaho Power's avoided costs do not
17 change until a new QF has actually been added to the
18 resource portfolio. A QF that has not signed a contract
19 cannot yet be considered part of the resource portfolio.
20 However, once a contract is signed for one QF, the
21 avoided cost rate for all successive QF5, even if they
22 are still in negotiation of a contract, should also
23 change accordingly.
24 Q. What assumptions and variables do you recommend
25 remain fixed between IRP filings?
CASE NO. GNR-E-11-03 STERLING, R (Di) 24
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i A. I recommend that all variables and assumptions
2 other than the ones I just mentioned remain fixed. This
3 would include, for example, the timing and composition of
4 the portfolio of new resources to be added, new resource
5 costs, resource characteristics, operational
6 characteristics, transmission assumptions, discount rates
7 and other financial assumptions.
8 Contract Length
9 Q. Idaho Power is proposing that maximum contract
10

length be reduced from 20 years to 5 years. Do you agree
with the Company's proposal?
12 A. Yes, I do.
13 Q. Has the Commission ever before limited
14 contracts to five years or less?
15 A. Yes, it has. The Commission's policy with
16 respect to standard contract length has evolved over the
17 years. From 1980 when PURPA was first implemented in
18 Idaho, through 1987, utilities were obligated to offer
19 QFs up to 35-year contracts. The reason for the 35-year
20 maximum contract length was that 35 years was the
21 amortization period allowed for similar utility-owned
22 facilities. A contract length that matched the project's
23 amortization schedule served to make financing easier,
24 and in effect, helped encourage QF development.
25 In 1987 (See Case No. U-1500-170, Order No.
CASE NO. GNR-E-11-03 STERLING, R (Di) 25
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i 21630) the Commission shortened the standard contract
2 length to 20 years reasoning that risk and uncertainty
3 inherent in long-range forecasting increases dramatically
4 with time and that a shorter contract term would reduce
5 that risk. The Commission ruled that contracts longer
6 than 20 years would be available to QFs only upon a
7 persuasive showing of need.
8 Nine years later, in 1996, the Commission again
9 reexamined the issue of contract length. In Order No.
10 26576 in Case No. IPC-E-95-9, the Commission further
11 shortened the required contract length from 20 years to
12 five years for projects 1 MW and larger. In 1997, the
13 Commission extended the five-year contract length
14 limitation established for large QFs to smaller than 1 MW
is QFs as well. (See Case No. IPC-E-97-9, Order No. 27111).
16 Shortly after approving Idaho Power's Application to
17 limit all QF contracts to five years, both Avista and
18 PacifiCorp petitioned for and received approval to
19 limit all QF contracts to five years. (See Case Nos.
20 WWP-E-97-8, Order No. 27212; UPL-E-97-4, Order No.
21 27213)
22 In 2002, the Commission increased maximum
23 contract length from 5 years back to 20 years. The
24 Commission explained that when it earlier had reduced
25 maximum contract length to five years, there was an
CASE NO. GNR-E-11-03 STERLING, R (Di) 26
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i expectation of widespread deregulation, more competitive
2 markets, and greater reliance on short-term market
3 purchases. However, by 2002, the Commission recognized
4 that each of Idaho's regulated electric utilities were
5 constructing or had recently constructed long-term new
6 generation resources. In restoring 20 years as the
7 maximum contract length, the Commission reasoned that a
8 longer contract better coincides with the amortization
9 period or planned resource life of the renewable or
10 cogeneration resources being offered, better reflects the
ii amortization period of generation projects constructed by
12 the utilities themselves and will coincidently provide a
13 revenue stream that will facilitate the financing of QF
14 projects. (See Order No. 29029).
15 Q. During the approximately five and a half year
16 period when contract length was limited to five years
17 (September 1996 through May 2002), how many PURPA
18 contracts were signed?
19 A. There was only one PURPA contract signed in
20 Idaho during this time frame. However, at the time, the
21 eligibility cap for published rates was also limited to
22 facilities one megawatt or smaller. In addition,
23 published rates were also quite low, primarily due to low
24 natural gas prices. Furthermore, most PURPA hydro and
25 cogeneration projects had already been developed, while
CASE NO. GNR-E-11-03 STERLING, R (Di) 27
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wind, solar and biogas technologies had yet to fully
2 develop. The combination of all of these factors, not
3 shortened contract length alone, caused very few PURPA
4 projects to be developed in Idaho during this time
5 period.
6 Q. But won't a five-year limit on maximum contract
7 length, if approved, severely limit the ability of
8 projects to obtain financing, thus making extensive
9 project development unlikely?
10 A. I agree that development would likely slow
11 considerably, at least under PURPA. However, large
12 facilities could still be developed with long-term
13 contracts in response to utility requests for proposal,
14 just as they are in most of the rest of the country.
is Alternatively, projects could also sign PURPA contracts
16 and renew them every five years as long as PURPA remains
17 in effect. If the significantly lower rates proposed by
18 various parties in this proceeding are ultimately adopted
19 by the Commission, any project signing a contract at low
20 rates would probably not want to be locked into those
21 rates for 20 years, and would welcome the opportunity to
22 sign new contracts at five-year intervals;
23 Q. Do you believe that the Commission has a
24 responsibility to ensure contract lengths are long enough
25 to enable QFs to obtain financing?
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A. No, not necessarily. Long-term contracts have
2 been used by the Commission in the past to boost
3 development of PURPA projects. However, circumstances
4 have changed. It would be contrary to the public
5 interest to encourage PURPA development at a time when it
6 IS not needed to serve customers and at a time when poor
7 economic conditions strain customers' ability to pay. I
8 believe it would be good public policy for the Commission
9 to use effective tools, such as limiting maximum contract
10 length, to control the pace of PURPA development.
11 Q. Are there any requirements under PURPA
12 regarding contract length?
13 A. No, FERC's regulations implementing PURPA are
14 silent on contract length.
15 Q. Are there other reasons why you believe that
16 maximum contract length should be shortened to five
17 years?
18 A. Yes, there are. When the SAR was changed from
19 a coal-fired resource to a gas-fired resource in 1995,
20 fuel became a much larger portion of the avoided cost
21 rate. By comparison, fuel is a far more substantial
22 portion of costs for a gas-fired resource than for a
23 coal-fired resource. In fact, for the gas-fired CCCT now
24 used as the SAR, fuel represents approximately two thirds
25 of the project costs. Currently, the fuel component of
CASE NO. GNR-E-11-03 STERLING, R (Di) 29
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i costs must be estimated based on 20-year forecasts. As
2 history has demonstrated, it can be extremely difficult
3 to accurately forecast gas prices just a few years into
4 the future, let alone 20 years into the future.
5 Similarly, under the IRP methodology, much of the cost
6 upon which PURPA rates are based is driven by fuel
7 prices. Gas-fired generation is on the margin much of
8 the hours of the year; consequently, electric market
9 prices are frequently closely tied to natural gas prices.
10 A five-year contract allows contract rates to be adjusted
11 regularly to more accurately reflect current fuel prices.
12 The shorter the term of the contract, the more
13 frequently prices can be adjusted to ensure they
14 accurately represent the true value of the power. A
15 shorter term contract helps to minimize risk for both the
16 buyer and the seller.
17 Q. Some people have argued over the years that
18 PURPA projects, because the prices are established at the
19 start of the contract term and are fixed for the 20 years
20 of the contract, present little or no fuel price risk
21 compared to gas-fired generation acquired by utilities.
22 Do you agree?
23 A. No, I do not. Although there may be no price
24 uncertainty associated with long-term PURPA contracts,
25 that is not the same as having no price risk. Prices
CASE NO. GNR-E-11-03 STERLING, R (Di) 30
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i established at the start of a long-term contract could
2 prove to be too high or too low compared to other
3 alternatives or to market prices in effect throughout the
4 term of the contract. A long-term contract locks in
5 those prices, regardless of what happens with market
6 prices. Because 100 percent of PURPA costs are passed on
7 to customers through PCAs, ratepayers are fully exposed
8 to the risk that PURPA rates may prove to be too high.
9 Fuel costs associated with utility-owned
io

resources are also passed on to customers, partly through
base rates and partly through PCA5. However, fuel costs
12 are tracked annually and rates are adjusted accordingly.
13 Consequently, while customers are exposed to fuel price
14 risk for both PURPA and utility-owned resources, the
15 annual adjustment of rates for Utility-owned resources
16 exposes customers to less risk for utility-owned
17 resources than for PURPA resources. Moreover, recovery
18 of costs for utility-owned resources is not guaranteed.
19 However, as previously stated, once a PURPA contract is
20 approved by the Commission, customers are obligated to
21 pay 100 percent of the costs.
22 Q. Is it your position that contracts be limited
23 to five years for all QFs, or only those eligible for
24 rates determined under the IRP methodology?
25 A. It is my position that contracts be limited to
CASE NO. GNR-E-11-03 STERLING, R (Di) 31
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five years only for those QFs eligible for rates
2 determined under the IRP methodology. Twenty-year
3 contracts should continue to be available to QF5 under
4 the SAR methodology.
5 QF Contracting Procedure & Rules
6 Q. PacifiCorp proposes in this case that a tariff
7 (Schedule 38) be adopted specifying contracting
8 procedures and rules for QF contracts. Do you support
9 this proposal?
10 A. Yes, I do. The Commission has never maintained
rules or required specific procedures in the past, but I
12 believe that they could be helpful now for both the
13 utilities and project developers. A fair, consistent set
14 of rules and procedures would inform both parties of
15 their responsibilities, informational requirements, and
16 timelines. It could also help to alleviate complaints.
17 Q. Would you recommend that the tariff proposed by
18 PacifiCorp be adopted by the Commission for use by all
19 three utilities?
20 A. No. I believe that each utility needs to
21 develop its own tariff tailored to meet its own needs,
22 subject to approval of the Commission. I would recommend
23 that each of the utilities be directed to prepare similar
24 tariffs to PacifiCorp's Schedule 38, and that a separate
25 docket be opened for review and comment on the specific
CASE NO. GNR-E-11-03 STERLING, R (Di) 32
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a. details that would be contained in each proposed tariff.
2 Although Idaho Power has stated that it supports a
3 similar tariff, it has not submitted a draft proposed
4 tariff.
5 Advance Contract Commitment, Price Lock-in
6 Q. Avista proposes that utilities should not be
7 required to execute PURPA contracts more than five years
8 ahead of expected deliveries. Do you agree with this
9 proposal?
10 A. Although I agree with the objective of the
ii proposal, I think it may be difficult to implement in
12 order to ensure that it does not conflict with the
13 utility's obligation to offer to purchase under PURPA.
14 Avista has made a second proposal, however,
15 that could successfully achieve a similar objective.
16 Avista's second proposal is that rates contained in a
17 PURPA contract not be locked in more than two years ahead
18 of commercial operation. Project developers typically
19 need to obtain a power sales agreement and the certain
20 avoided rates contained within it before they can obtain
21 financing to proceed with their project. Completing the
22 project can then take several years, depending on the
23 type and size of the facility. A developer might
24 experience delays for various reasons while he diligently
25 pursues his project. But delays can also occur due to
CASE NO. GNR-E-11-03 STERLING, R (Di) 33
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1 deliberate actions or inactions of the developer. Many
2 things can change during the time a developer is working
3 on his project, including power prices. Although I
4 believe that a developer needs price certainty and the
5 assurance of a utility obligation to purchase during the
6 reasonable course of developing a project, I do not
7 believe that the same price certainty and assurance
8 should be preserved indefinitely. Few projects achieve
9 commercial operation within two years of contract
10 execution, but most achieve it within five years. I
11 believe five years after contract approval is a
12 reasonable period of time to preserve rates contained in
13 an initial contract. If a project cannot be completed
14 and achieve commercial operation within five years, then
15 the utility, while it may still have a continuing
16 obligation to purchase under PURPA, should be permitted
17 to recompute rates in the contract based on whatever
18 rules, assumptions and methods are in place at the time
19 of the recomputation. Avoided cost rates could either
20 increase or decrease in the interim between contract
21 execution and commercial operation; consequently, I
22 believe it would be fair to permit the utility to
23 recompute new rates after five years if they would be
24 lower than the original rates, or to maintain the
25 original rates if the QF's failure to achieve commercial
CASE NO. GNR-E-11-03 STERLING, R (Di) 34
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operation as scheduled is not the fault of the utility.
2 Q. Avista proposes that utilities be permitted to
3 terminate contracts 180 days beyond the committed online
4 date in the contract if projects fail to come online, and
5 that a security deposit for liquidated damages be due at
6 the time a legally enforceable obligation is incurred -
7 i.e., Avista states, when the utility has tendered a
8 contract and the QF developer executes and returns the
9 tendered contract obligating the utility to purchase
10 contract output. Do you agree with these proposals?
11 A. I think utilities can already insert conditions
12 in contracts that allow them to terminate contracts 180
13 days beyond the committed online date when projects fail
14 to come online; therefore, I do not believe that any
15 further authorization from the Commission is necessary.
16 Security deposits for delay liquidated damages
17 have become standard in all recent PtJRPA contracts. A
18 requirement that a security deposit for liquidated
19 damages be due when a QF developer executes and returns
20 the tendered contract would be a change from current
21 practice. The Commission has never specified in any of
22 its orders the timing of when a security deposit is due.
23 However, I believe Avista's proposal has merit. It seems
24 fair that if a QF can unilaterally impose a legally
25 enforceable obligation on a utility, the QF should
CASE NO. GNR-E-11-03 STERLING, R (Di) 35
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i contemporaneously incur a corresponding obligation to
2 perform backed by a posting of required security for
3 liquidated damages.
Curtailment (Idaho Power Schedule 74)
5 Q. Idaho Power proposes that the Commission
6 approve a tariff (Schedule 74) that governs operational
7 dispatch of QFs, including curtailment under certain
8 circumstances. Do you support the proposed tariff?
9 A. Yes, I do. The proposed tariff would establish
10 rules under which Idaho Power could curtail certain QFs
11 if, due to operational circumstances, purchases from the
12 QF would otherwise require the Company to dispatch higher
13 cost, less efficient resources to serve system load or to
14 make base load resources unavailable for serving the next
15 anticipated load.
16 Q. Doesn't Idaho Power already have authority to
17 curtail Us under certain circumstances?
18 A. Yes, they do under Schedule 72 and under the
19 terms of all PURPA power sales agreements, but only in
20 response to system integrity issues. Schedule 72
21 generally addresses interconnection of non-utility
22 generation, but specifically includes provisions that
23 allow disconnection under circumstances in which
24 ". . .the Seller's operation or maintenance of the
25 Generation Facility or Interconnection Facilities is
CASE NO. GNR-E-11-03 STERLING, R (Di) 36
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i unsafe or may otherwise adversely affect the Company's
2 equipment, personnel, or service to its customers."
3 Unlike Schedule 72 that gives the Company authority to
4 curtail, the proposed Schedule 74 addresses policies and
5 procedures for operational dispatch of Idaho Power's own
6 resources in addition to QF resources.
7 Q. If Idaho Power already has authority to curtail
8 QFs under certain circumstances, why is an additional
9 tariff necessary?
10 A. As I stated, the existing Schedule 72 gives the
11 utility the authority to curtail under certain
12 circumstances, but the proposed Schedule 74 details
13 specific policies and procedures to be followed under
14 curtailment. I am aware that Idaho Power has curtailed
15 wind projects on its system several times this year
16 following the same procedures outlined in the proposed
17 tariff. If Idaho Power intends to follow these
18 procedures, it would be desirable that they be contained
19 in a Commission-approved tariff to help ensure clarity,
20 consistency, and fairness.
21 Schedule 74 would also address Idaho Power's
22 ability to curtail for reasons related to system
23 efficiency and economics, reasons not allowed under
24 Schedule 72.
25 Q. Idaho Power proposes that Schedule 74 apply to
CASE NO. GNR-E-11-03 STERLING, R (Di) 37
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1 all QF facilities, both existing and new, that have
2 Generator Output Limiting Controls (GOLCs) installed. Do
3 you believe that, if approved, the Company would have the
4 authority to apply the proposed tariff to existing
5 facilities whose contracts were in place prior to the new
6 tariff being adopted?
7 A. Yes, I do. As explained by Idaho Power witness
8 Tessia Park, FERC rules at 18 CFR 292.304(f) includes a
9 provision that relieves utilities from an obligation to
10 purchase during any period which, due to operational
1]. circumstances, purchases from QFs will result in costs
12 greater than those which the utility would incur if it
13 did not make such purchases, but instead generated an
14 equivalent amount of energy itself. Because this is a
15 part of FERC rules, I think Idaho Power has always had
16 that authority whether or not it is expressly spelled out
17 in a contract or a tariff.
18 Q. Has clarification of 18 CFR 292.304(f) ever
19 been made by FERC?
20 A. Yes. In Order No. 69, FERC clarified that 18
21 CFR 292.304(f) was intended to deal with a certain
22 condition which can occur during light loading periods—
23 conditions that I believe are properly explained by Idaho
24 Power witness Park.
25
CASE NO. GNR-E-11-03 STERLING, R (Di) 38
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i Renewable Energy Credits
2 Q. PacifiCorp in this case took a position that
3 ownership of Renewable Energy Credits (REC5) associated
4 with QF5 should be assigned to the utilities. Idaho
5 Power pointed out that REC ownership is being debated in
6 Case No. IPC-E-11-15 and that, at the time Idaho Power
7 filed its testimony, the Idaho Legislature was
8 considering legislation addressing REC ownership. Avista
9 was silent on the issue. Do you believe that this issue
10 should be addressed in this proceeding?
ii A. Yes, I do. Depending upon one's point of view,
12 REC5 are either directly or indirectly associated with
13 the capacity and energy produced and sold to utilities by
14 nearly all QFs. Despite the fact that Idaho has not
15 adopted any standards requiring that utilities possess
16 REC5 (i.e., renewable portfolio standards), they
17 nevertheless are generated by QFs and have value to
18 whichever entity is deemed to own them. In addition, the
19 disposition of REC5 between the utility and the QF owner
20 is typically addressed in most new power sales
21 agreements, except for those in which the parties are
22 unable to agree on REC ownership in which case the
23 agreements are silent regarding ownership. While some
24 recent contracts have been silent, others have granted
25 full REC ownership to the QF owner, others have split REC
CASE NO. GNR-E-11-03 STERLING, R (Di) 39
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ownership 50/50 between the QF owner and the utility from
2 the beginning of the contract throughout its entire term,
3 while still others have split REC ownership with the QF
4 possessing them for the first half of the contract term
5 and the utility possessing them for the last half.
6 Although negotiation of REC ownership has proven to be
7 possible in some instances, parties have reached an
8 impasse in other cases. Nonetheless, in every case, REC
9 ownership has been an extremely contentious issue. I
10 believe that rules need to be established in order to
11 ensure consistency and to avoid disputes.
12 Q. PacifiCorp witness Clements proposes that
13 Environmental Attributes (RECs, green tags) generated by
14 a QF go to the utility whenever the QF sells energy to
15 the utility and receives compensation for that energy at
16 approved avoided cost rates. What is your position on
17 this issue?
18 A. I agree with Mr. Clements that REC ownership
19 should be decided in favor of the utilities, but my
20 reasoning is a bit different.
21 Q. Can you summarize some of the common arguments
22 made concerning REC ownership?
23 A. Yes. Arguments justifying REC ownership have
24 been made throughout the country from the time when REC5
25 were first defined. The arguments generally fall into
CASE NO. GNR-E-11-03 STERLING, R (Di) 40
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i one or more of several categories. First, some arguments
2 focus on the responsibility and timing of creation of the
3 REC5. Some argue that the QF developer should own the
4 RECs because the developer made the investment and took
the risk in building the renewable facility, that the
6 RECs are created the instant the kWhs are generated, and
7 that absent the facility, no RECs would exist. Others
8 argue that RECs are not created until the kWhs are sold
9 to the utility, and that RECs owe their very existence to
10 the fact that the energy was purchased by the utility,
11 thus the utility should own the RECs.
12 A second class of arguments, similar to Mr.
13 Clements', focuses on a belief that REC ownership by the
14 utility is a necessary condition of purchases made from
15 QF5 because of the presumption that renewable attributes
16 are an implied requirement for QFs under PURPA, and that
17 stripping these attributes destroys the very essence of
18 the product PURPA obligates utilities to purchase. This
19 argument suggests that the purchaser of the energy should
20 be entitled to all of the attributes of that energy.
21 A third class of arguments focuses on costs.
22 The basic argument is that the avoided cost rate should
23 take into account REC ownership. If the purchase by the
24 utility of a kWh includes a bundled REC, then the price
25 paid by the utility should be higher than if only the kWh
CASE NO. GNR-E-11-03 STERLING, R (Di) 41
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1 alone is delivered.
2 Q. Why do you believe that REC ownership should be
3 decided in favor of the utilities?
4 A. All of the arguments summarized above have
5 merit and may be persuasive in justifying REC ownership
6 be either the utility or the QF. In the end, however, I
7 believe that the public interest is paramount in any
8 decision on REC ownership in Idaho. In my opinion, the
9 public interest is best served if REC ownership is
io granted to the utilities.
ii For example, if Idaho was in a position where
12 additional incentive was needed in order to stimulate
13 further development of renewables or achieve an RPS
14 standard, then it might be reasonable to assign ownership
15 of REC5 to QF project owners so that they would have an
16 additional revenue stream that could enhance project
17 economics. However, as recent history demonstrates,
18 Idaho is not in a situation where renewables development
19 is stalled or needs to be accelerated.
20 If the real purpose of an RPS standard is to
21 stimulate renewables development, then it seems that
22 objective is achieved once a renewable project is built.
23 If a utility did not receive the REC5 from that project
24 and instead was forced to purchase or obtain REC5
25 elsewhere, then it seems that twice the incentive would
CASE NO. GNR-E-11--03 STERLING, R (Di) 42
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be created for developing renewables projects—once for QF
2 developers who sell RECs to out-of-state entities and
3 once for the utility who must purchase RECs to satisfy
4 its own requirements. Although such a result may not be
5 intended, if an RPS requirement did exist and had to be
6 met, utilities could be in a position of having to
7 acquire RECs just to meet the standard when it might
8 otherwise have been able to meet the standard using RECs
9 associated with QFs from which it must purchase power
10 under PURPA.
11 Q. Has FERC provided any guidance regarding REC
12 ownership?
13 A. Yes, some. FERC has made clear that REC
14 ownership is a matter for states to decide. The key case
15 addressing REC ownership is the following: American Ref-
16 Fuel Company, 105 FERC ¶ 61,004 (2003)
17 In American Ref-Fuel, several QFs had
18 petitioned FERC for an order declaring that avoided cost
19 contracts entered into pursuant to PURPA, absent express
20 provisions to the contrary, do not inherently convey to
21 the purchasing utility any REC5. Id. at 61,005. In
22 response, FERC addressed the relationship between PURPA
23 contracts for the sale of QF capacity and energy and the
24 ownership of RECs. FERC specifically declared the
25 following:
CASE NO. GNR-E-11-03 STERLING, R (Di) 43
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1 23... .RECs are relatively recent creations of
the States. Seven States have adopted Renewable
2

Portfolio Standards that use unbundled REC5.
What is relevant here is that the REC5 are
3 created by the States. They exist outside the
confines of PURPA. PURPA thus does not address
4

the ownership of RECs. And the contracts for
sales of QF capacity and energy, entered into
5

pursuant to PURPA, likewise do not control the
ownership of the REC5 (absent an express
6 provision in the contract). States, in creating
RECs, have the power to determine who owns the
7

REC in the initial instance, and how they may
be sold or traded; it is not an issue
8 controlled by PURPA.
9 24. We thus grant Petitioners' petition for a
declaratory order, to the extent that they ask
10 the Commission to declare that contracts for
the sale of QF capacity and energy entered into
11 pursuant to PURPA do not convey REC5 to the
purchasing utility (absent an express provision
12

in a contract to the contrary) . While a state
may decide that a sale of power at wholesale
13

automatically transfers ownership of the state-
created RECs, that requirement must find its
14 authority in state law, not PURPA.
15 American Ref-Fuel, 105 FERC at 61,007.
16 Thus, FERC concluded that REC5 are created by
17 the State and controlled by state law, not PURPA, and
18 that they may be decoupled from the renewable energy.
19 More specifically, FERC ruled that states have the power
20 to determine who owns RECs.
21 Q. FERC's order in Am Ref-fuel says that contracts
22 for the sale of QF capacity and energy entered into
23 pursuant to PURPA do not convey REC5 to the purchasing
24 utility. Wouldn't it therefore be reasonable to conclude
25
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1 that RECs are owned by the QF, absent an express
2 provision in the contract to the contrary?
3 A. No, I contend that such an interpretation can
4 only be reached by taking language from FERC's order out
5 of context. The Petitioners in Am Ref-fuel specifically
6 asked for a declaration that "contracts for the sale of
7 QF capacity and energy entered into pursuant to PURPA do
8 not convey RECs to the purchasing utility." FERC's
9 answer granted the petition and addressed the precise
10 question it was asked to decide. It went no further,
i1 except to say that REC ownership is a matter for states
12 to decide. FERC was not asked to rule on the converse
13 question that contracts for the sale of QF capacity and
14 energy entered into pursuant to PURPA do not convey RECs
15 to the QF. I believe a reasonable interpretation of
16 FERC's order is that contracts under PURPA, absent
17 express provisions, do not convey RECs to either party,
18 nor do they dictate REC ownership. Any interpretation
19 that implies that FERC stated that QFs own RECS seems to
20 me to be a case of starting with a conclusion and working
21 backwards, and requires reading far more into FERC's
22 decision than is actually there. Similarly, any
23 suggestion that FERC determined that RECs are owned by
24 the QFs would, in my opinion, be inconsistent with FERC's
25 determination that REC ownership is a matter for states
CASE NO. GNR-E-11-03 STERLING, R (Di) 45
5/4/2012 STAFF
to decide.
2 Q. Aside from the need for the Commission, the
3 Legislature, or the courts to determine REC ownership,
4 are there pricing issues associated with RECs that need
5 to be considered in setting avoided cost rates?
6 A. Yes, there are. For example, under the IRP
7 methodology, a utility's 20-year portfolio of new
8 resources is modeled in computing avoided cost rates.
9 Each utility's 20-year resource portfolio contains some
io renewable plants because they either represent the lowest
ii cost resources or because they help satisfy expected RPS
12 requirements or both. The utility would possess the REC5
13 associated with resources contained in its preferred
14 portfolio, and presumably any price premium associated
15 with those RECs would be included in the cost of the
16 projects. Consequently, the cost of RECs would, already
17 be accounted for in computing avoided cost rates using
18 the IRP methodology. Therefore, a utility paying the
19 computed avoided cost to a QF under the IRP methodology
20 should be entitled to ownership of the RECs.
21 Under the SAR methodology, however, because the
22 SAR is a gas-fired resource that does not produce RECs
23 and the QF is presumably a renewable resource that does
24 produce RECs, some adjustment to the avoided cost rates
25 may be necessary. If the utility is deemed to own the
CASE NO. GNR-E-11-03 STERLING, R (Di) 46
5/4/2012 STAFF
1 RECs associated with the QF, then an adjustment to the
2 avoided cost rates is necessary because capacity and
3 energy from the QF simply offsets capacity and energy
4 otherwise provided by the SAR. The RECs would be a
5 unique attribute of the power provided by the QF. The
6 utility would then be expected to pay some amount in
7 addition to the published avoided cost rates if it wished
8 to own the REC5.
9 Q. Does this conclude your direct testimony in
10 this proceeding?
ii A. Yes, it does.
12
13
14
15
16
17
18
19
20
21
22
23
24
25
CASE NO. GNR-E-11-03
5/4/2012
STERLING, R (Di) 47
STAFF
go go go
Comparison of Proposed IRP Methodology Rates
Levelized Rates for 20-yr Contract Term, January 2013 Online Date
$120
$100
• $80
• $60 a, N
a,
a, —J $40
o 4.CJ)(DI- O) $20
r.Jrl Oct
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S36.68 $37.07
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 4TH DAY OF MAY 2012,
SERVED THE FOREGOING DIRECT TESTIMONY OF RICK STERLING, IN CASE
NO. GNR-E- 11-03, BY MAILING A COPY THEREOF, POSTAGE PREPAID, TO THE
FOLLOWING:
DONOVAN E WALKER
JASON B WILLIAMS
IDAHO POWER COMPANY
P0 BOX 70
BOISE ID 83707-0070
MICHAEL G ANDREA
AVISTA CORPORATION
1411 EMISSION AVE
SPOKANE WA 99202
ROBERT D KAHN
NW & INTERMOUNTAIN POWER
PRODUCERS COALITION
1117 MINOR AVE STE 300
SEATTLE WA 98101
ROBERT PAUL
GRAND VIEW SOLAR II
15690 VISTA CIRCLE
DESERT HOT SPRINGS CA 92241
THOMAS H NELSON
RENEWABLE ENERGY COALITION
P0 BOX 1211
WELCHES OR 97067
R GREG FERNEY
MIMURA LAW OFFICES PLLC
2176 E FRANKLIN RD
STE 120
MERIDIAN ID 83642
DANIEL E SOLANDER
TED WESTON
ROCKY MOUNTAIN POWER
201 S MAIN ST STE 2300
SALT LAKE CITY UT 84111
PETER J RICHARDSON
GREGORY M ADAMS
RICHARDSON & O'LEARY
515 N 27TH STREET
BOISE ID 83702
DON STURTEVANT
ENERGY DIRECTOR
J R SIMPLOT COMPANY
P0 BOX 27
BOISE ID 83707-0027
JAMES CARKULIS
EXERGY DEVELOPMENT GROUP OF
IDAHO LLC
802 W BANNOCK ST STE 1200
BOISE ID 83702
JOHN R LOWE
RENEWABLE ENERGY COALITION
12050 SW TREMONT ST
PORTLAND OR 97225
BILL PISKE MGR
INTERCONNECT SOLAR
DEVELOPMENT LLC
1303 E CARTER
BOISE ID 83706
CERTIFICATE OF SERVICE
RONALD L WILLIAMS
WILLIAMS BRADBURY
1015 W HAYS ST
BOISE ID 83702
BRAIN OLMSTEAD
GENERAL MANAGER
TWIN FALLS CANAL CO
P0 BOX 326
TWIN FALLS ID 83303
TED DIEHL
GENERAL MANAGER
NORTH SIDE CANAL CO
921 N LINCOLN ST
JEROME ID 83338
TED S SORENSON P E
BIRCH POWER COMPANY
5203 SOUTH I TH EAST
IDAHO FALLS ID 83404
M J HUMPHRIES
BLUE RIBBON ENERGY LLC
3470 RICH LANE
AMMON ID 83406
DEAN J MILLER
McDEVITT & MILLER LLP
P0 BOX 2564
BOISE ID 83701
KEN MILLER
SNAKE RIVER ALLIANCE
BOX 1731
BOISE ID 83701
WADE THOMAS
DYNAMIS ENERGY LLC
776 E RIVERSIDE DR
STE 15
EAGLE ID 83616
MEGAN WALSETH DECKER
SR STAFF COUNSEL
RENEWABLE NW PROJECT
421 SW 6 TH AVE STE 1125
PORTLAND OR 97204
BILL BROWN CHAIR
BOARD OF COMMISSIONERS
OF ADAMS COUNTY ID
P0 BOX 48
COUNCIL ID 83612
GLENN IKEMOTO
MARGARET RUEGER
IDAHO WINDFARMS LLC
672 BLAIR AVE
PIEDMONT CA 94611
ARRON F JEPSON
BLUE RIBBON ENERGY LLC
10660 SOUTH 540 EAST
SANDY UT 84070
BENJAMIN J OTTO
ID CONSERVATION LEAGUE
P0 BOX 844
BOISE ID 83702
MARV LEWALLEN
CLEAR WATER PAPER CORP
STE 1100
601 W RIVERSIDE AVE
SPOKANE WA 99201
ENERGY INTEGRITY PROJECT
TAUNA CHRISTENSEN
769N 1100
SHELLEY ID 83274
~ 44~~t
CRETARY
CERTIFICATE OF SERVICE