20120131Kalich Direct.pdf

CE1\!'-r,DI". . .'. .,~"l\ t: . :,.J "..' l ~t ~".., i'"~'I~'V'STA'
Corp.
2011 JAN 31 AM 10: 14
l D /\ ;"'1 C) ,F~,4e~;L;: C: r~ .~~. t ¡
J amtmlJtlJ 120 l(2U i\'; M ! S,j ¡ u r¡
Utilities Commission
ashington Street
93702
Direct Testimony of Clint Kalich on Behalf of Avista Corporation
IPUC Case No. GNR~E-ll-03
Dear Ms. Jewell:
Please find enclosed for filing an original and nine copies ofthe Direct Testimony of
Clint Kalich on behalf of A vista Corporation for filing in the above-referenced proceeding. The
first enclosed copy is hereby designated as the reporter's copy. Please let me know if you have
any questions regarding this filing.
Sincerely,
Michael G. Andrea
Senior Counsel
Enclosures
cc: Service List
oi:C'E. 1\!!=O.'l',\L. ,;f.- ; i! ,;¡ i"
BEFORE THE IDAHO PUBLIC UTILITIES C0MM~O~N 31 AM 10:14
IN THE MATTER OF THE COMMISSION'S )
REVIEW OF PURP A QF CONTRACT )
PROVISIONS INCLUDING THE )
SURROGATE AVOIDED RESOURCES ) CASE NO. GNR-E-ll-03
(SAR) AND INTEGRATED RESOURCE )
PLANING (IRP) METHODOLOGIES FOR )
CALCULATING PUBLISHED AVOIDED )
COST RATES )
TESTIMONY OF CLINT KALICH
AVISTA CORPORATION
JANUARY 31, 2012
1 I. INTRODUCTION AND TESTIMONY OVERVIEW
2 Q. Please state your name, the name of your employer, and your business
3 address.
4 A.My name is Clint Kalich. I am employed by A vista Corporation
5 ("Avista") at 1411 East Mission Avenue, Spokane, Washington.
6 Q.Please state your educational background and professional
7 experience.
8 A.I graduated from Central Washington University in 1991 with a Bachelor
9 of Science Degree in Business Economics. Shortly after graduation, I accepted an
10 analyst position with Economic and Engineering Services, Inc. (now EES Consulting,
11 Inc.), a northwest management-consulting firm located in Bellevue, Washington. While
12 employed by EES, I worked primarly for municipalities, public utilty districts, and
13 cooperatives in the area of electrc utility management. My specific areas of focus were
14 economic analyses of new resource development, rate case proceedings involving the
15 Bonnevile Power Administration, integrated (least-cost) resource planing, and demand-
16 side management program development.
17 In late 1995, I left Economic and Engineering Services, Inc. to join Tacoma
18 Power in Tacoma, Washington. I provided key analytical and policy support in the areas
19 of resource development, procurement, and optimization, hydroelectric operations and re-
20 licensing, unbundled power supply rate-making, contract negotiations, and system
21 operations. I helped develop, and ultimately managed, Tacoma Power's industrial market
22 access program serving one-quarer of the company's retail load.
Case No. GNR-E-ll-03
Januar 31, 2012
Kalich, C. (Direct)
A vista Corporation
Page 2 of35
1 In mid-2000 I joined Avista and accepted my curent position assisting the
2 Company in resource analysis, dispatch modeling, resource procurement, integrated
3 resource planing, and rate case proceedings. I have paricipated in proceedings before
4 the Commission since 2000, and cases surrounding PURP A beginning in 2002.
5 Q.Why are you providing testimony before the Commission today?
6 A.Avista wants to ensure that its customers receive fair value for the
7 electricity they purchase. This is the basic premise of Public Utility Regulatory Policy
8 Act (PURPA) law: utilities should pay no more than what they otherwise would for
9 Qualifying Facility (QF) deliveries of capacity and energy (i.e., the utilities actual
10 avoided costs). A misalignment between the prices utilties pay for QF power and the
11 utilities' actual avoided costs stil exists in some cases in Idaho. Recent QF wind
12 development history ilustrates how important it is for rates paid to QFs to reflect the
13 purchasing utilities' actual avoided costs. My testimony provides a framework under
14 which the rates paid for QF power under PURPA canot greatly exceed the utilities'
15 actul avoided costs and, therefore, the value customers receive for such power.
16 Q.Please provide an overview of your testimony?
17 A.My testimony will first provide some background discussions on topics
18 A vista wishes to highlight in this hearing. These include:
19 1) principles of avoided cost,
20 2) key avoided costs concepts - energy and capacity,
21 3) defining utility need,
22 4) valuing power output during periods of utility deficit and surlus, and
Case No. GNR-E-ll-03
Januar 31, 2012
Kalich, C. (Direct)
A vista Corporation
Page 3 of35
1 5) bifucation of rates to reflect capacity and energy costs avoided by the purchase of
2 QF power.
3 After providing some background, my testimony makes the following
4 recommendations:
5 1)
6 2)
7 3)
8 4)
9
10
11 5)
12
13
14 6)
15
16 7)
17
18 8)
19 III
20 III
21 III
22 III
23 /I
continue limiting published rate eligibilty for variable generators to 100 kW,
bifucate all PURP A rate schedules into capacity and energy,
provide capacity payments only in those years where the utility is deficient,
during periods of utility energy surlus, PURP A rates should be discounted for
the transmission costs, including transmission losses, associated with re-sellng
the surlus power into the market,
PURP A contracts should be signed no earlier than five years before commercial
operation; fixed prices should be made available no earlier than two years before
commercial operation,
PURP A contracts should retain meaningful liquidated damage and termination
provisions,
SAR gas prices should be updated anually for published rates using the Energy
Information Administration's Anual Energy Outlook, and
the Commission should not determine REC ownership in this docket.
Case No. GNR-E-ll-03
Januar 31, 2012
Kalich, C. (Direct)
A vista Corporation
Page 4 of35
1 II.AVOIDED COST BACKGROUND DISCUSSION
2 Principles of Avoided Costs
3 Q.Please provide a general discussion of PURP A and avoided costs as it
4 pertains to this proceeding.
5 A. PURP A was passed in 1978 to help create a market for non-utility electricity
6 supplies.
1 PURP A, and its associated regulations, obligates utilities to buy "energy and
7 capacity which is made available from a qualifying facility" at rates not exceeding the
8 incremental costs to the utility of electric energy andlor capacity which, but for the
9 purchase from the QF, the utilty would generate itself or purchase from another source?
10 The rates for such purchases "shall be just and reasonable to the electric consumer. . . .,,3
11 While the obligation to purchase is mandated by federal law, pricing and many of the
12 terms and conditions of PURPA contracts are left to the state. States have been given
13 wide discretion in setting the rates, terms, and conditions for PURP A contracts, but are
14 required "to put into effect.. . standard rates for purchases from qualifying facilities with a
15 design capacity of 100 kilowatts or less.,,4
16 In Idaho, the Idaho Public Utilties Commission (Commission) is responsible for
17 implementing PURP A. The Commission sets rates and methodologies for all QF
18 developers wishing to sell their output in the State of Idaho to one of the utilities
19 regulated by the Commission.
i Today it can be argued that QF developers have adequate access to the marketplace absent the PURA.
For example, utilities generally procure new long-term supplies of electricity through regulated or quasi-
regulated competitive acquisition processes that QF developers can bid into. Federal laws and regulations
also now obligate utilties to sell or build transmission capacity to/for 3rd paries, enabling QF developers to
sell their output to other utilty systems or at the major trading hubs.218 C.F.R. § 292.101(b)(6) (defining "avoided costs").
318 C.F.R. § 292.304(a)(l)(i).
4 18 C.F.R. § 292.304(c).
Case No. GNR-E-ll-03
Januar 31, 2012
Kalich, C. (Direct)
A vista Corporation
Page 5 of35
1 Q. Please expand on the definition of avoided cost.
2 A. Avoided cost is a complex concept, as the 33-year history of PURP A and its
3 implementation in Idaho shows. FERC regulations define avoided costs as meaning "the
4 incremental costs to an electric utility of electric energy or capacity or both which, but for
5 the purchase from the qualifying facility or qualifying facilities, such utility would
6 generate itself or purchase from another source."s FERC allows for differentiation of the
7 avoided cost rate based on a number of factors, including consideration of: a) daily and
8 seasonal shaping, b) the ability of the utility to dispatch the resource, c) the demonstrated
9 reliabilty of the resource, d) the term, termination notice, and sanctions for non-
10 compliance, e) the extent to which outages can be usefully coordinated with utility needs,
11 f) the usefulness of the resource during system emergency, g) the reduction of fossil fuel
12 use, and h) line loss savings or costs attributable to the resource.6
13 A simplified interpretation of this provision is that customers should pay no more
14 for a QF purchase than a least-cost alternative to it. And fuher to this point, customers
15 should pay only an amount equal to the costs that they actually avoid by making the QF
16 purchase; in other words, if no costs are being avoided, the QF developer should not
17 receive compensation for its deliveries under PURP A.
18 Energy and Capacity Definitions
19 Q.How does one define "energy" in the context of PURP A?
20 A.PURP A does not specifically define energy. According to a March 2011
21 paper by the Pacific Northwest Utilities Conference Committee (PNUCC), energy
518 C.F.R. § 292.101(b)(6).
6 18 C.F.R. § 292.304(e).
Case No. GNR-E-1I-03
Janua 31, 2012
Kalich, C. (Direct)
A vista Corporation
Page 6 of35
1 "measures the quantity of electrical power (i.e., flow) over time."? It is measured in watt-
2 hours. In the northwest, energy is generally measured in average megawatts because it
3 measures average consumption over a period of time.
4 Q.What is the definition of "capacity" in the context of PURP A?
5 A.In contrast to energy, capacity measures the ability to produce power to
6 meet system load requirements.8 It is a generic term often requiring the use of a
7 descriptor, such as "nameplate" capacity or "net winter" capacity. In the context of
8 PURP A, many of the avoided cost considerations listed earlier in my testimony require
9 differing types of capacity.
lOAn important concept for PURP A in Idaho is the on-peak capacity contribution of
11 a resource. In other words, the resource's ability to reliably generate during times ofthe
12 utility system's peak. Absent the ability to reliably generate during peak-period hours,
13 there are no avoided capacity costs because, notwithstanding the existence or non-
14 existence of the QF, the utility will need to build or otherwse acquire a resource to
15 generate during times of the utility system's peak. FERC has acknowledged this point in
16 its rules.9 Therefore, a Q F that canot be relied on to generate durng times of system
17 peak does not avoid any utility capacity costs. It follows that a QF that cannot be relied
18 on to provide on-peak generation should not receive any payment for the capacity portion
19 of the PURP A avoided cost rate.
7 htt://pnucc.org/ documents/CapabilitiesotResourcesReportandMemoweb. pdf.
8 The "abilty" to produce power, in the case of wind and other variable and fuel-limited renewables, also
means that the resource has fuel adequate to generate power during the peak system load requirement.9 18 C.F .R. § 292.304( e )(2) states that the rate shall be based on: ''the availabilty of capacity or energy
from a qualifying facility during the system daily and seasonal peak periods."
Case No. GNR-E-ll-03
Januar 31, 2012
Kalich, C. (Direct)
A vista Corporation
Page 7 of35
1 Q.How should the on-peak contribution of a QF resource, and the level
2 of its capacity payment, be determined?
3 A.The contribution should be determined in a maner similar to how the
4 utilty identifies the on-peak capacity contribution of its other resources. A first step is to
5 determine the expected, or average, on-peak contribution. For example, the QF
6 developer must supply a "12x24" matrix of its expected future deliveries as par of the
7 contracting process. This means the QF developer provides one estimated 24-hour shape
8 of power output for each calendar month. From this shape much can be learned. For
9 example, an irrigation canal hydroelectricity facility's l2x24 matrix will show clearly
10 that no generation is delivered to the utility during the winter months. So, in Avista's
11 case where on-peak capacity benefits are defined by winter output, an irrigation canal
12 hydroelectricity facility is not able to generate during Avista's winter peak and, therefore,
13 the capacity contribution is zero.
14 The analysis is more complicated if the utility system peaks during the summer
15 when the canal project is expected to generate at some level durng peak load periods.
16 Capacity planing based on statistical averages, like the l2x24 matrix, has the potential
17 to compromise reliability because during approximately half of futue contract years the
18 resource will not perform at the average level of capacity. A statistical approach to
19 quantifying a Q F resource's capacity, similar to how the utility does its other capacity
20 planing, should be applied. Absent a long period of historical record to evaluate the
21 contribution, the QF resource should receive a capacity contribution based on levels for
22 similar resources identified by the utilty in its Integrated Resource Plan (IRP).
Case No. GNR-E-ll-03
Janua 31, 2012
Kalich, C. (Direct)
A vista Corporation
Page 8 of35
1 Q.Does this approach work for resources other than irrigation canal
2 hydro used in your example above?
3 A.Yes. For Avista's IRP the on-peak capacity contribution of each major
4 resource tye is input into its Preferred Resource Selection Model (PRiSM). I
5 recommend that values from the IRP be used to set the on-peak capacity values in
6 PURP A contracts except possibly for wind where a small contribution might be used.
7 Based on Avista's IRP, the following on-peak contributions would be applied to QF
8 developer projects.
10 Contributions are reduced for operating reserves the utility is
9 obligated to provide as par of its membership in the Northwest Power PooL.
10 Table 1 - Avista On-Peak Capacity Contributions from 2011 IRP
11
12
Resource Contribution Resource Contribution
Canal Hvdro 0%Solar 5%
Wind 0%Biomass 93%
13 Q.You mention that you might support a small on-peak contribution for
14 wind. What level wil you support?
15 A.Without a geographically diversified portfolio of wind it is difficult to
16 assign anyon-peak contribution value for wind. It is A vista's concern for maintaining
17 system reliability that it assigns no capacity value to wind in its IRP. This said, the
18 Northwest Power and Conservation Council (NPCC) uses a regional on-peak capacity
19 benefit of five percent. To be consistent with the NPCC, I will support a five percent on-
20 peak capacity contribution for wind for PURPA projects. However, Avista will continue
21 assignng wind a zero on-peak capacity value in its planing assessments, including the
10 Values represent winter on-peak contribution. For example, canal hydro operates during the spring and
summer months, with no output during the winter. Avista's wind rating is low due to the lack of wind
diversity in its portfolio.
Case No. GNR-E-ll-03
Janua 31, 2012
Kalich, C. (Direct)
A vista Corporation
Page 9 of35
1 IRP, until such time as an adequately diverse portfolio of wind exists in its service
2 terrtory.
3
4
5
Definition of Utilty Need
Q. Should utilty need be a factor in the price paid for QF power?
6 A.Yes. There is a vast difference in the costs avoided by the QF resource
7 depending on whether the utility is filling a resource deficit with QF power, or the utilty
8 already has resources adequate to meet its load obligations. When deficit, avoided costs
9 are those that would be paid for a least-cost alternative resource or resources providing
10 equivalent value. When the utility is in a surlus position, it wil not avoid any costs as a
11 result of the QF purchase; at most, the actual value of the QF purchase to the utility is
12 only the avoided fuel costs at existing facilties. A more generous interpretation of the
13 PURP A obligation is to compensate a QF developer durng times of system surlus at the
14 market price received for the sale of the energy net of delivery costs to a market trading
15 hub.
11
16 Q.In Order 29124 the Commission eliminated from consideration utility
17 need in the calculation of published avoided cost rates, relying substantially on the
18 concerns expressed by Staff. What has changed to support your position that the
19 Commission should reverse course?
20 A.In Order 29124, the Commission expressed nine reasons in support of
21 removing the first deficit year. The concerns in 2002 should not exist today.
11 For example, the short-term PURP A rate is 85% of the market index price, with the reduction intended to
compensate the utility for delivery of the surlus to the market.
Case No. GNR-E-ll-03
Januar 31, 2012
Kalich, C. (Direct)
A vista Corporation
Page 10 of35
1 Q.What was the first reason, and what has changed to again support
2 considering first year deficits?
3 A.The first concern was the lack of regular filings before the Commission
4 that outline utilty deficit years. Since 2002 much has changed. Utilties now fie
5 biennial IRPs outlining future deficit year explicitly. Each IRP is developed with
6 paricipation from Commission staffs and other interested staeholders.
7 To determine Avista's future needs, one needs to look no fuher than the third
8 paragraph of our August 2011 IRP fiing. The document states our needs very clearly:
9 "absent new resource additions or new conservation measures, anual energy deficits
10 begin in 2020. . . the Company will be short 98 MW of sumer capacity in 2019. . . winter
11 capacity deficits begin at 42 MW in 2020." Language similar to this has been included in
12 all recent Avista IRPs as far back as 2003. The fact that utilities are clearly defining their
13 resource needs in regularly-fied IRP's should eliminate this concern.
14 Q.What was the second reason, and has it been resolved?
15 A.The Commission was concerned with the lack of clarity of what exactly
16 the deficit year represented, and whether the determination should be based on an energy
17 or capacity need. As expressed in my previous answer, Avista now tracks both energy
18 and capacity deficiency positions. My proposal, to be fleshed out later in testimony, is to
19 pay for each of these components separately based on separate utility needs for each.
20 With this resolved, the 2002 concern should be fully resolved.
21 III
22 III
Case No. GNR-E-ll-03
Januar 31,2012
Kalich, C. (Direct)
A vista Corporation
Page 11 of35
1 Q. What was the third reason, and why should it no longer concern the
2 Commission?
3 A. The third concern was that key planing assumptions greatly affect the
4 result, and that assumptions can var by utility. Whle it stil is true that planing
5 assumptions differ between the utilities and affect the ultimate deficit year or years,
6 utility IRP processes are subject to significant oversight, both by Idaho Commission Staff
7 and other utility commission staff, and interested paries-including utilty customers and
8 potential QF developers. Each utility certainly is different and, therefore, each utility
9 needs to have different assumptions. As such, the balancing of loads and resources that
10 each utility undertes is for reasons much greater than PURP A, including system
11 reliabilty, least cost, and meeting environmental and oither social policies.
12 The bottom line is that, with regularly-updated IRPs benefitting from public and
13 Commission oversight, there is a consistent basis for determining load and resource
14 balance such as developed in the utility's IRP.
15 Q. The fourth concern was that utilties prepare their own load forecasts
16 with little oversight, and that they can be manipulated. Has this changed?
17 A. I am not aware of any load forecast concerns over the five past IRPs (2003-
18 present) planng cycles that I have led. But, as explained in my answer to the third
19 concern, regular IRP timelines should eliminate this concern too. The utility load
20 forecast is presented to Staff and other paricipants in the Company's public IRP process;
21 questions about the forecast can be aired and addressed in that public process.
22 III
23 III
Case No. GNR-E-ll-03
Janua 31, 2012
Kalich, C. (Direct)
A vista Corporation
Page 12 of35
1 Q. What was the fifth concern, and why should it no longer be of concern?
2 A. The Commission was concerned there was not adequate consistency
3 regarding how long-term market purchases were considered in utilty planng. This
4 concern has been addressed. I believe there is general consensus now that any contract,
5 including one for PURP A power, that obligates a seller to sell and a utilty to buy power
6 should be included in the load and resources tabulation.
7 Q. Staff also reasoned in 2002 that the difference between PURP A rates
8 during surplus and deficit periods were not great and that the importance of the
9 deficit year had diminished. Does this reasoning hold today?
10 A. No. With a more accurate payment for QF power through the bifucation of
11 energy and capacity payments as proposed in this testimony, there is a significant
12 difference between payments in deficit and surlus periods. As I explained above, the
13 needs of the utility are essential to successfully honor avoided cost principles, especially
14 in light of the significant additions of variable generation resources to utility systems
15 since 2002. And, as I will show later in my testimony, it is imperative that the
16 Commission recognze the deficit years for energy and capacity to ensure appropriate
17 avoided cost payments are made.
18 Q. What was the seventh concern? Is it stil valid?
19 A. The seventh concern was that utilities tend to be surlus in the near term,
20 and that avoided cost rates should not provide incentives for a utility to increase its length
21 to avoid having to purchase PURPA power. It is often true that utilities are surlus in
22 early years; being so is an essential par of providing reliabile utility service. It also is
23 true that QF developers would be affected by these surluses were they to receive lower
Case No. GNR-E-ll-03
Janua 31, 2012
Kalich, C. (Direct)
A vista Corporation
Page 13 of35
1 early-year payments during surlus years. But this effect is a reflection of true avoided
2 costs. It is not reasonable to hold a utility system short both of capacity and reliability
3 simply to promote QF development. So in the early years of a long-term contract, QF
4 developers might receive a lower payment reflective only of the energy value of their
5 projects. But out beyond this time the payment will increase with the utilty's need for
6 the QF resource. QF developers also have the opportunity to contract with the utility and
7 postpone their development and deliveries until such time as a deficiency occurs.
8 Q. Does reasoning in 2002, that PURP A project development does not have
9 a large impact on utilties' load and resource balance, hold today?
10 A. No. As recent history shows, PURPA development can star and stop very
11 quickly. The result can be many contracts and hundreds of megawatts of new, and often
12 uneeded, supplies. These figures are not small, especially for a utility like Avista that is
13 growing at fewer than 30 MW per year.
14 Q. Do you have any comments with regard to the last reason that
15 supported the 2002 decision to eliminate the consideration of the utility deficit year?
16 A. Yes. Staff s position in 2002 was that volatile energy prices of that period,
17 and the SAR's linkage to them during periods of utility surlus, posed difficulty when
18 estimating PURP A payments during surlus years. Today we have better options to
19 avoid ths volatilty and provide the QF developer with a more stable price in surplus
20 years. As explained later in my testimony, I believe that it is possible to provide a fixed
21 payment during surlus years that does not fluctuate over the contract term, and is tied to
22 the actul expected operating costs of the SAR.
Case No. GNR-E-ll-03
Januar 31, 2012
Kalich, C. (Direct)
A vista Corporation
Page 14 of35
1 Q.In re-establishing the deficit year, how should utilty needs be
2 defined?
3 A.Utility needs should be defined using a publicly-available information
4 source-the biennial utility IRP. The IRP defines the future needs for both energy and
5 capacity on the utility's system, and, as noted before, is developed with participation
6 from Commission staffs and other stakeholders. Each plan defines the timeframe of
7 future deficits.
8 Q.Should load changes since the IRP be considered in the tabulation of
9 utilty need?
10 A.Yes. Limited updates should be considered, including changes resulting
11 from a new load forecast, and new contract obligations (e.g., new PURPA contracts) and
12 deliveries incurred since the publication ofthe IRP. Ifthere is a concern over, for
13 example, the load forecast, the Commission could be consulted to assist the paries in
14 resolving their differences. Alternatively, and at their option, utilities could fie anual
15 IRP resource balance updates with the Commission.
16 Q.What happens if a utilty is deficit in one of the two PURP A
17 components (energy or capacity), and not in the other?
18 A.As I explain in more detail in other portions of my testimony, QF
19 developers should only receive payments for capacity when the utility has a capacity
20 need. Compensation for energy should be based on a separate tabulation of energy needs.
21 If the utility is in a deficit energy position, the payment should be determined
22 independently of the capacity need and based on the value of that energy to the utilty. If
Case No. GNR-E-ll-03
Januar 31, 2012
Kalich, C. (Direct)
A vista Corporation
Page 15 of35
1 the utility is surlus energy, the energy payment should be reduced by the costs of
2 delivering the surlus power to the market (i.e., transmission and associated losses).
3 PURPA Rates During Periods of Utilty Deficit and Surplus
4 Q. How does the concept of utilty need apply to PURP A?
5 A. The principle concept to utilities buying QF power is paying no more than
6 avoided cost. In other words, what least-cost resource and/or acquisition would be
7 avoided with the delivery of QF power under PURPA? Where no costs are avoided by
8 the utilty with the addition of a QF, the QF does not reduce the utility's system costs. In
9 the most basic interpretation, the utility would pay nothing for QF power where no costs
10 were avoided; however, another policy position could be that where a market exists for
11 sellng surlus energy from the QF, the QF is paid the market value for its energy.12 No
12 similar active market exists for capacity and no significant value can be obtained through
13 remarketing capacity surluses created by QF purchases. Because of this, QF developers
14 should receive payments for capacity only when the utility is deficit.
15 Bifurcation of the PURP A Rate
16 Q.Do rates presently paid to QF developers accurately reflect actual
17 avoided costs?
18 A.It depends. Avoided cost rates calculated using the IRP methodology for
19 QFs above the eligibilty cap for published avoided cost rates (i.e., 100 kW for wind and
20 solar QFs, and 10 aMW for all other QFs) reflect actual avoided costs because the
12 While historically utilties doing business in Idaho have paid for QF power even when they are in a
surlus position because there has been a market for such energy, there may be strctual changes in the
region, such as higher levels of wind, increased transmission constraints, and increased prevalence of
negative prices, that may at some point require are-evaluation of that position.
Case No. GNR-E-ll-03
Januar 31, 2012
Kalich, C. (Direct)
A vista Corporation
Page 16 of35
1 specific values of the resource are considered uniquely. However, the prices paid to
2 QF's under published avoided cost rates can exceed actual avoided costs.
3 Q.Please explain why prices paid to QFs under published avoided cost
4 rates can exceed actual avoided costs.
5 A.The Commission sets rates that utilities must pay all QF developers below
6 an eligibility cap based on a Surogate Avoided Resource (SAR). The SAR used to set
7 the published avoided cost rates is a gas-fired combined-cycle combustion turbine
8 (CCCT). Today all QF resources below the cap are compensated at a single rate
9 assuming equivalency to the SAR-I.e., the delivery of both energy and capacity-even if
10 the QF resource is variable and/or provides little or no capacity.u As a result, the
11 published rates for variable resources can significantly exceed actual avoided costs. This
12 result is not equitable to customers in the case of variable energy QFs like wind, as
13 payments are inclusive of energy and capacity, yet the costs of new capacity investment
14 are not being avoided.
15 Q.What are the consequences of a published avoided cost rate exceeding
16 actual avoided cost?
17 A.The recent experience of some utilities in Idaho shows a "boom" in QF
18 wind development can be a significant consequence that likely would not have been
19 possible absent the structure of published avoided cost rates in Idaho that provided a
20 published avoided cost rate that exceeded the actual avoided costs of wind QFs. That is,
13 Some differentiation exists based on time of day, seasonality, and integration charges. Wind resources
are subject to a wind integration charge that reduces the QF payment by approximately 10%; however, this
reduction is for the consumption of capacity due to wind integration, not a discount for the fact that the
resource does not provide on-peak capacity. Wind "consumes" capacity because existing non-wind
capacity resources must be dedicated to following and integrating the variable wind generation.
Case No. GNR-E-ll-03
Janua 31, 2012
Kalich, C. (Direct)
A vista Corporation
Page 17 of35
1 inflated PURPA prices incented QF developers to constrct more wind QFs and sell the
2 output in Idaho. The result is that utility customers bear inflated costs.
3 III. THE COMMISSION SHOULD LIMIT VARIABLE GENERATOR
4 PUBLISHED RATE ELIGIBILITY TO 100 KW
5
6 Q. Should the Commission continue to limit variable generation resource
7 (i.e., wind and solar) access to published rates to 100 kW?
8 A.Yes. The ability of variable generation resources to break into smaller
9 projects solely for the purose of qualifying for published rates is well documented and
10 should not be allowed. The best means to prevent this is to keep the 100 k W cap for
11 varable generation resources. Furher, the Commission's 100 kW limit for varable
12 generator published rate eligibilty is a reasonable limitation and is consistent with federal
13 law. I support the continuation of this limit indefinitely. Large variable QF resource
14 additions should be considered on a case-by-case basis to ensure that the prices paid for
15 the QF output reflect the actul avoided cost associated with the paricular QF resource.
16
17
18
19
20
IV.CUSTOMERS ARE BEST PROTECTED THROUGH BIFURCATION OF
PURP A RATES INTO SEPARATE ENERGY AND CAPACITY
COMPONENTS
Q. Should the Commission continue to offer a single combined rate for
21 capacity and energy?
22 A.No. The avoided costs of varous QF technologies can be vastly different.
23 Some technologies, such as landfill gas, act very much like the SAR, providing both
24 signficant contributions in meeting on-peak demand (i.e., capacity), as well as energy.
25 Other resources, such as wind, provide little or no capacity and, therefore, the purchase of
26 the output from such resources under a PURP A contract will not avoid significant
27 capacity investments in alternative resources. Payments to such resources providing little
Case No. GNR-E-ll-03
Janua 31, 2012
Kalich, C. (Direct)
A vista Corporation
Page 18 of35
1 or no capacity should be lower than a SAR-equivalent resource. But resources providing
2 on-peak capacity similar to the SAR, but generating less energy on an anual basis than
3 the SAR, such as drop canal hydro projects located in a sumer-peaking system, have the
4 potential for much higher per- MWh rates under bifucation.
5 Q.Please explain why QF developers should be paid separately for
6 capacity and energy.
7 A.Under FERC regulations, a utility obligation exists to purchase energy and
8 capacity from a QF at a price reflective of the value of a QF resource.14 Furher, FERC
9 allows that rates "may differentiate among qualifying facilities using various technologies
lOon the basis of the(ir) supply characteristicsY One of the largest differences among QF
11 facilties is their ability to provide varying levels of energy and capacity.
12 Q.How do you propose that the Commission ensure that actual avoided
13 costs are not exceeded?
14 A.The Commission's adoption of a lower eligibility cap (100 kW) for wind
15 and solar resources is a significant first step in mitigating the problems associated with
16 paying published avoided cost rates to variable resources because: (i) it is now more
17 difficult for wind and solar QF developers to disaggregate large projects to take
18 advantage of published avoided cost rates, and (ii) the avoided cost rate for most wind
19 and solar projects wil be calculated using the IRP methodology, which more accurately
20 reflects the actual avoided costs.16 The Commission should retain this limitation. The
21 Commission also should bifucate avoided cost rates into the separate components of
14 18 CFR § 292.303
15 18 CFR § 292.304(a)(3)
16 The IRP Methodology allows the use of updated pricing assumptions (e.g., curent natual gas prices,
utilty need for the resource).
Case No. GNR-E-ll-03
Januar 31, 2012
Kalich, C. (Direct)
A vista Corporation
Page 19 of35
1 energy and capacity. In this way, those resources not reducing utility system
2 requirements (i.e., capacity) or bringing value similar to a utility option are not
3 compensated beyond their actual value.
4 Q.Do you have a recommended method to separate the values of
5 capacity and energy for published rates?
6 A.Yes. And the basic principles apply to both the SAR and IRP
7 Methodologies. The Commission is charged with establishing appropriate avoided cost
8 rates for QF facilities as it relates to capacity and energy. While there might be other
9 methods available to the Commission, for published rates the simplest would be to
10 change slightly the strcture of payments.
11 The following table provides an overview of my recommended method for
12 establishing published avoided cost rates.
13 Table 2 - Recommended Published Rate Bifurcation Method
14
15
Rate Method Summary Units
Capacity CCCT SAR for "Fueled" projects $/MWh
Enerav CCCT SAR for "Non-Fueled" projects less CCCT SAR for "Fueled" projects $/MWh
16 Q.Please explain your reasoning for creating a new published capacity
17 rate.
18 A.Each published rate-eligible QF developer enabling the utility to avoid
19 capacity investments, irrespective of its fuel source, receives a payment based on the
20 "Fueled" rate and its on-peak capacity contribution. The present Fueled rate
21 approximates the fixed costs of owning and operating the SAR, and approximates the
Case No. GNR-E-ll-03
Janua 31, 2012
Kalich, C. (Direct)
A vista Corporation
Page 20 of35
1 cost of capacity.17 No new base calculations are required to determine the capacity
2 payment because the Commission already calculates a Fueled rate.
3 Q.How would your proposed method account for two resources with
4 similar on-peak capacity contributions, but different generation characteristics?
5 A.It is not fair to pay one resource with a low capacity factor and an
6 equivalently high on-peak contribution the same per-MWh payment as second base load
7 plant operating with a relatively high capacity factor all year round. Using the method,
8 the low capacity factor resource would receive much lower total compensation even
9 though the resource provided the same on-peak capacity benefit to the utilty. To ensure
lOa similar payment is made for a similar on-peak capacity contribution, the first step is to
11 covert the SAR per-MWh payment level to a total anual capacity payment. This is
12 accomplished by multiplying the per-MWh rate of the Fueled schedule by the assumed
13 net capacity factor of the SAR resource. This value is then divided by the expected
14 anual capacity factor of the specific QF resource to arrive at a per-MWh rate. The
15 following table ilustrates this concept where you have differing resources providing
16 different on-peak capacity contributions. Consistent with my proposal, I used the
17 levelized fueled rate as a proxy for capacity value.
18 III
19 III
20 III
21 III
22 III
17 It does not include fuel and variable operating costs, those generally associated with energy production.
Case No. GNR-E-ll-03
Januar 31,2012
Kalich, C. (Direct)
A vista Corporation
Page 21 of35
1 Table 3 - Comparison of QF Project Capacity Payments
2
3
Line Item SAR Geo Hydro Solar Wind Note
1 Resource Size (MW)1 1 1 1 1 assumption
2 Capacity Contribution (%)100 100 100 35 5 assumption
SAR 20-Year Lev. Fueled from present Avista
Rate (2013 First Year PURPA rate
3 Delivery, $/MWh)25.51 schedule
4 Net Capacity Factor 92.0%85.0%34.0%22.6%33.0%assumption
line 1 * line 4 * 8,760
5 Annual Generation (MWh)8,059 7,446 2,978 1,980 2,891 hours
Annual Capacity Payment SAR line 6 * line 2 /
6 ($0005)206 206 206 72 10 SARline2
7 Capacity Payment ($/MWh)25.51 27.61 69.03 36.35 3.56 line 6/line 5
4
5 The table shows that payments can greatly exceed or fall below the SAR rate
6 based on the capacity contribution and expected, or average, output of the resource. The
7 hydro example shows how this low capacity factor resource receives a per-MWh capacity
8 payment much higher than the SAR resource. The table also shows how a solar resource,
9 even though it has a much lower on-peak capacity contribution can stil receive a per-
10 MWh payment exceeding the SAR resource with a 100% on-peak contribution.18 The
11 table shows that the payment for wind is much lower than the SAR, primarily because of
12 its low on-peak contribution.
13 Q.What do you mean by "on-peak contribution"?
14 A.For customers to derive a capacity benefit (i.e., for the utility to avoid
15 capacity investment costs) from the PURPA project, the QF must be capable of reliably
16 generating during peak load hours of the year. If the QF canot be relied on to generate
17 during the utilty's peak load hours of the year, the utilty wil have to build or otherwse
18 procure a resource that the utility can rely on to generate during those peak load hours
19 and, therefore, the QF does not avoid any capacity investment costs. This means the QF
20 must be capable of reliably providing output during peak hours in the winter months for
18 The price assumes the solar resource is located in a sumer-peaking utilty location. Where located in a
winter-peaking utilty's terrtory, like Avista, the payment likely wil be much smaller.
Case No. GNR-E-ll-03
Januar 31, 2012
Kalich, C. (Direct)
A vista Corporation
Page 22 of35
1 Avista, and likely during the sumer months for both Idaho Power and PacifiCorp.19
2 Eligibilty for capacity payments must be tied to the expected on-peak contribution of the
3 QF resource.
4 Q.Do you have any other recommendations with regard to published
5 rate capacity payments?
6 A.Yes. With my proposal I recommend changing the rate for capacity in the
7 published tables to a per-MW price instead of a per-MWh price, and then footnote that
8 the payment made to the QF developer wil be dependent on the capacity factor and on-
9 peak capacity contribution of the resource. It might also be useful to provide one or more
10 example calculations to show how the capacity payment is "translated" to a per-MWh
11 charge. To make things less confusing, the "Fueled" rate schedule should be re-named as
12 the "Capacity" rate schedule.
13 Q.Table 3 explains that the per-MWh capacity payment rises as the
14 capacity factor ofthe resource falls. What is to prevent a QF developer from under-
15 estimating the QF's capacity factor to obtain higher total compensation for its
16 capacity contribution?
17 A.After the anual SAR-based capacity payment is calculated, it should
18 serve as a cap on total payments in any given year to remove any incentive for a QF to
19 under estimate output.20 If the QF developer is shown over time, say over two or five
20 years, to have substantially under-estimated the QF's capacity factor, I believe that the
21 capacity rate should be adjusted downward accordingly.
19 Idaho Power and PacifiCorp are "sumer-peaking" utilties, as documented in their biennial integrated
resource plans.
20 Adjusted based on the specific capacity factor of the QF resource.
Case No. GNR-E-ll-03
Januar 31, 2012
Kalich, C. (Direct)
A vista Corporation
Page 23 of35
1 Q.Please explain your reasoning for a new published energy rate.
2 A.Under my proposal, QF projects eligible for the Fueled rate would receive
3 payments for their energy as they do today-based on a gas index. But "Non-Fueled"
4 projects like wind and biomass would receive payments based on the variable operating,
5 varable maintenance and fuel costs associated with the SAR. This value is arived at by
6 reducing the Non-Fueled SAR rates by the Fueled (Capacity) rates.
7 Q.Do you have any other recommendations with regard to published
8 rate energy payments?
9 A.Yes. To again make things less confusing, I would name this modified
10 "Non-Fueled" rate schedule (i.e., the Non-Fueled rate schedule less the Fueled rate
11 schedule) as the "Energy" rate schedule.
12 Q.How would the changes you propose affect the major QF
13 technologies?
14 A.The major change is that QF resources eligible for published avoided cost
15 rates, to the extent they provide significantly less capacity than the SAR, receive a lower
16 rate more commensurate with the costs they enable the utility to avoid. For example, if a
17 wind resource provides a five percent peak capacity value to the utilty, it would witness
18 a reduction in the capacity component of the avoided cost rate that would be reflected in
19 its PURPA compensation. Biomass resources likely would be affected only modestly, if
20 at all, because they tend to provide system capacity all year round. Solar would fall
21 somewhere in the middle based on its expected contribution to utility system peak.
22 Hydro resources would benefit greatly relative to the existing structue. See the
23 following table, a continuation of Table 3.
Case No. GNR-E-ll-03
Januar 31, 2012
Kalich, C. (Direct)
A vista Corporation
Page 24 of35
1
2
Table 4 - Comparison of QF Project Total Payments
Line Item SAR Geo Hydro Solar Wind Note
1 Resource Size (MW)1 1 1 1 1 assumption
2 Capacity Contribution (%)100 100 100 35 5 assumption
SAR 20-Year Lev. Fueled from present Avista
Rate (2013 First Year PURPA rate
3 Delivery, $/MWh)25.51 schedule
4 Net Capacity Factor 92.0%85.0%34.0%22.6%33,0%assumption
line 1 * line 4 * 8,760
5 Annual Generation (MWh)8,059 7,446 2,978 1,980 2,891 hours
Annual Capacity Payment SAR line 6 * line 2 I
6 ($OOOs)206 206 206 72 10 SAR line 2
Capacity Payment
7 ($/MWh)25.51 27,61 69.03 36.35 3.56 line 6/1ine 5
SAR line 10 - SAR
8 Eneray Payment ($/MWh)45.45 line 7
9 Intearation ($/MWh)0 0 0 (6.50)(6.50)
SAR from schedules
Total (combined) PURPA other resources,
10 Rate ($/MWh)70.96 73.06 114.48 75.30 42.51 lines 7 + 8 + 9
3
4 As shown, PURP A rates (line 10) can vary significantly depending on the
5 resource type under this proposaL. It is also important to point out that these prices
6 assume the utilty has both capacity and energy needs throughout the delivery period?l
7 The anual capacity payment (line 6) for geothermal is the same as the SAR because the
8 expected output is the same, even though the per- MWh rate differs due to a difference in
9 expected anual MWh output. Solar obtains a capacity payment premium relative to the
10 SAR because its capacity contribution relative to its capacity factor is higher than the
11 SAR ratio?2 Wind receives a much lower overall payment because only a small on-peak
12 capacity contribution is attibuted to the resource. The largest winner using this method
13 is the canal drop hydro facility because it, in this example, provides capacity and operates
14 at a low capacity factor relative to the SAR. So to compensate it for avoided capacity
21 Drop canal hydro facilties would not receive a capacity payment in winter-peaking systems, since the
resource does not generate during the winter. The on-peak capacity payment likely would differ for solar
in a winter-peaking system because the resource generates significantly less during winter on-peak hours
relative to on-peak sumer hours. There also would be discounts in periods where the purchasing utilty is
surlus energy to account for costs necessar to deliver the surlus energy to a market trading hub.22 Again, this assumes that the solar resource is located in a sumer-peaking utilty territory where on-peak
contrbutions are higher than in a winter-peaking system.
Case No. GNR-E-ll-03
January 31,2012
Kalich, C. (Direct)
A vista Corporation
Page 25 of35
1 costs, its rate per MWh must rise. Please note that I have simplified the energy payment
2 line (line 8) for hydro, solar and wind in this example. These resources wil receive a
3 modified payment depending on their specific energy shape over the year. For example,
4 a solar plant likely would obtain a slightly larger energy payment because its generation
5 is correlated with peak load periods. Wind might get a slightly lower energy payment
6 given that wind tends to have a slight bias toward off-peak hours.
7 Q.How wil the bifurcation affect resources obtaining their pricing
8 through the IRP Method?
9 A.The IRP Method wil conceptually follow the strcture described above.
10 The utility purchasing from a QF will pay the QF for energy based on the energy costs
11 avoided by the utility. The utility also will pay only for capacity based on the capacity
12 costs that are avoided due to the QF.
13
14
15
16
V.QF DEVELOPERS SHOULD RECEIVE PAYMENTS FOR CAPACITY
ONLY WHEN THE UTILTY IS DEFICIT
Q. What should QF developers be paid when the utilty is deficit?
17 A.When the utilty is deficient, the QF developer should be compensated
18 based on the costs the utility and its customers avoid by not having to invest in alternative
19 power sources. This value is best identified by a recent competitive acquisition process
20 or the utility's latest IRP, both adjusted for any significant changes that have occured
21 since the time of the acquisition or publication of the IRP.23 This methodology is best
22 applied under the "IRP Methodology." Under published rates, the values during periods
23 Such changes can include load changes, new committed resources and contracts, fuel prices, and major
,changes to the wholesale marketplace (e.g., major additions or reductions to the regional resource stack).
Case No. GNR-E-ll-03
Januar 31, 2012
Kalich, C. (Direct)
A vista Corporation
Page 26 of35
1 of deficit are based not on the IRP or recent acquisitions, but instead on a surogate
2 avoided cost resource.
3 Q.What should QF developers be paid when the utilty is surplus
4 capacity?
5 A.The utility does not avoid any capacity costs by purchasing output from a
6 QF during those times when the utility does not have a need for capacity. Because there
7 is no need, and because no active capacity market exists in the northwest, the capacity
8 value of QF power durng surlus periods should be zero.
9
10
11
12
13
VI. QF DEVELOPERS SHOULD RECEIVE LOWER ENERGY PAYMENTS
DURING UTILITY SURPLUS PERIODS TO REFLECT THE COSTS OF
TRANSMITTING SURPLUS POWER TO MARKT
Q. Should QF developers be compensated for energy when the utility
14 Integrated Resource Plan (IRP) shows a surplus?
15 A.I am not greatly concerned about providing a payment for energy when the
16 IRP shows a utility energy surlus and no energy costs are actually avoided because a
17 fairly liquid market for energy at the Mid-Columbia trading hub exists. As footnoted
18 above, there may be a need to revisit this policy in the futue due to changes in
19 circumstaces. However, if utilties are required to pay for uneeded energy, the avoided
20 cost during the surlus period should reflect only the net value of QF surlus sold into the
21 short-term wholesale marketplace.
22 Q.What is the net value of QF energy when the utility is surplus and
23 does not avoid any costs by its purchase?
24 A.The value should reflect the market. For Avista in the northwest the
25 principle market is at the Mid-Columbia trading hub. The energy rate should not exceed
Case No. GNR-E-ll-03
Janua 31, 2012
Kalich, C. (Direct)
A vista Corporation
Page 27 of35
1 the Mid-Columbia price net of those costs incured to deliver the surlus power to that
2 point of delivery.
3 Delivery to the Mid-Columbia (i.e., through the use of transmission) is limited by
4 physical constraints. Avista has limited transfer capability, and surlus QF power sold at
5 the Mid-Columbia displaces other utility opportities to sell existing surluses of power
6 or to generate revenues from the resale of unused transmission to third paries.
7 Therefore, the price paid for QF power during surlus periods should be reduced by
8 Avista's transmission costs, which curently includes a $2.72 per kilowatt rate under
9 A vista's Open Access Transmission Tariff, and a defined three-percent energy loss
10 factor.
11 Q.What is the total transmission discount when applied to base load,
12 wind, solar, biomass and drop canal hydroelectricity plants?
13 A.Because transmission costs are not volumetric (i.e., based on the energy
14 generated), but instead on the level of reserved transmission capacity, the discount for
15 transmission costs varies depending on the capacity factor of the PURPA facility. The
16 following table estimates the discount for transmission costs based on an assumed
17 capacity factor for varous QF technology types.
18 11/
19 III
20 III
21 III
22 III
Case No. GNR-E-ll-03
Januar 31, 2012
Kalich, C. (Direct)
A vista Corporation
Page 28 of35
1 Table 5 - Transmission Costs of Surplus QF Electricity (for a 1.0 MW Project)24
Line Item Base Drop Wind Solar Note
Load/Canal
Biomass Hvdro
1 OF Net Capacit Factor 92.0%34.0%33.0%20.0%Assumption
2 OF Average Energy (MWh/mo.)672 248 241 146 Line 1 * 730 hrs in ava mo.
3 Transmission ($/kW-month)2.72 2.72 2.72 2.72 Avista OATT
4 Transmission ($/MWh)2.96 8.00 8.24 13.60 line 3/line 1
5 Enerav Rate ($/MWh)45.45 45.45 45.45 45.45 Table 4, line 8
6 Losses 3.0%3.0%3.0%3.0%Avista OATT
7 Losses ($/MWh)(1j 1.36 1.36 1,36 1.36 line 5 * line 6
8 Total Re-Marketing Costs 4.32 9.36 9.61 14.96 line 4 + line 7
9 As % of Energy Rate 9.5%.20.6%21.1%32.9%line 8/line 5
2
3 The table explains that the average cost of delivering surlus energy is dependent
4 on the capacity factor of the QF resource. Drop canal hydro and wind have a discount
5 that is approximately twice that of resources operating in more base-load confgurations.
6 Their discount is similar because their capacity factor is similar. Solar, due to its even
7 lower capacity factor, has a cost approximately three times that of base load generation.
8 Q.Should the net energy rate during surplus periods be reduced by the
9 full transmission rate? In other words, is it possible that the utilty wil have surplus
10 transmission from its marketing operations that could be used to transmit surplus
11 QF power to market without cost?
12 A.Yes, the rate should be reduced by the transmission rate. It is possible that
13 the merchant side of Avista's business might have surlus transmission capacity rights
14 from time to time. However, this transmission has value to customers as it can be resold
15 by A vista's transmission group to third paries. Reserving transmission for the purpose
16 of moving QF power to market would reduce those transmission revenues. Furher,
17 losses associated with transmitting power to the Mid-Columbia hub exist, irrespective of
18 the assumed cost of the transmission reservation.
24 Values shown are for a I MW facilty.
Case No. GNR-E-ll-03
Januar 31, 2012
Kalich, C. (Direct)
A vista Corporation
Page 29 of35
1 Q.Do you have any other observations that supporting your position
2 that surplus QF energy be discounted for the full cost of transmission?
3
i
Yes. In 2006, FERC issued Order No. 688, reiterating its 1995 findingA.
4 "that determinations of the avoided-cost rate must take into account all alternative
5 sources including third-pary suppliers and an electric utilty does not pay for electric
6 energy it does not need."is Accordingly, the Commission could decide that QF
7 developers should receive no payments when the utility is surlus.
8 Additionally, curent short-term PURP A rates recognize the impacts of market
9 delivery costs. Any PURP A power purchased this way receives a payment equal to 85%
10 of the Mid-Columbia index price. The reduction is an attempt to cover costs associated
11 with delivering surlus energy to the market. It is therefore reasonable to protect
12 customers against transmission costs when accepting surlus energy.
13
14
15
16
17
VII. PURP A CONTRACTS SHOULD NOT BE EXECUTED EARLIER THAN
FIVE YEARS BEFORE COMMERCIAL OPERATION; RATES SHOULD NOT
BE SET MORE THAN TWO YEARS PRIOR
Q. Should the abilty of the QF developer to sign a PURP A contract
18 ahead of scheduled commercial operation be limited?
19 A.Yes. The utility should not be expected to enter into a contract more than
20 five years ahead of expected deliveries. I would prefer to limit contracting to two years;
21 however, offering PURPA contracts with deliveries too few years into the futue would
22 limit developer opportunities to receive a capacity payment in the early years of the
25 New PURA Section 210(m) Regulations Applicable to Small Power Production and Cogeneration
Facilities, 117 FERC ir 61,078 (2006) ("Order No. 688") (emphasis added); see also Southern California
Edison Company and San Diego Gas & Electrc Company. 70 FERC ir 61,215 at 61,677-78,
reconsideration denied, 71 FERC ir 61,269 at 62,078 (1995).
Case No. GNR-E-ll-03
Januar 31, 2012
Kalich, C. (Direct)
A vista Corporation
Page 30 of35
1 contract. By committing itself to deliveries fuher into the futue, the QF developer wil
2 be more likely to receive compensation for both energy and capacity.
3 Q.Should the prices be set in a contract with delivery occurring as far as
4 five years into the future?
5 A.No. I recommend that prices be locked in no sooner than two years ahead
6 of commercial operation. Too many things affecting price can change over a five-year
7 term, both for the QF developer and the utility. This said, it would not be uneasonable
8 for the utility to provide estimates over time of the then-curent PURP A rates so that the
9 QF developer would be apprised of the value of its futue output.
10 VIII. PURP A CONTRACTS MUST HAVE MEANINGFUL LIQUIDATED
11 DAMAGE AND TERMINATION PROVISIONS
12
13 Q. Do you support the continued inclusion of liquidated damages provisions in
14 PURPA contracts?
15 A.Yes. Liquidated damages provisions, including adequate security to
16 ensure payment of liquidated damages if necessar, are one of two key protections a
17 utilty must have with any developer who might otherwse not exercise their "put option"
18 in the absence of an obligation on the par of the QF to perform. Once a PURP A contract
19 is executed by the paries it becomes a firm contract in the utility's resource stack and, as
20 such, the proposed QF resource postpones the development of other resource alternatives;
21 in other words, the contract then allows and obligates the Company to avoid the costs
22 associated with investing in its system to ensure reliable electricity service. To the extent
23 the PURP A developer does not honor its contract commitments the utility ends up at the
24 last moment having to procure other resources, potentially at higher cost. In the absence
25 of meaningful liquidated damages, the QF developer has a free option to either honor its
Case No. GNR-E-ll-03
Janua 31, 2012
Kalich, C. (Direct)
A vista Corporation
Page 31 of35
1 contractual commitment where the avoided cost rate under the contract (agreed to years
2 before commercial operation) is greater than its alternatives at the time of commercial
3 operation, break its commitment and sell to a 3rd par if it can secure a higher price, or
4 simply cease development where market conditions have changed.
5 Q.At what level should the Commission set the delay liquidated damages
6 deposit?
7 A.There is precedent in recent Idaho PURP A contracts for a $45 per kilowatt
8 deposit based on installed capacity. This deposit provides recourse to the utility where
9 the QF developer does not build its resource as contractually agreed. I recommend that
10 this level be the minimum required in all PURP A contracts.
11 Q.You stated that liquidated damages provisions are one of two key
12 protections that utilities need to protect against developers using PURPA as a
13 speculative put option. What is the second key protection?
14 A.The second key protection is meaningful termination rights if the QF fails
15 to achieve commercial operation within the timeframes established in the PURP A
16 contract.
17 Q.What are the termination provisions you envision as part of a PURP A
18 contract?
19 A.Liquidated damage provisions by themselves work well in a market where
20 prices are rising. The QF developer has an incentive to bring its project online because if
21 it does not, damages will be based on the difference between the higher market price of
22 replacement power and the lower PURP A contract price. This payment is backed by the
23 liquidated damages security.
Case No. GNR-E-ll-03
Janua 31, 2012
Kalich, C. (Direct)
A vista Corporation
Page 32 of35
1 In a period of fallng pnces, however, liquidated damages are not assessed
2 because market prices are lower than the contract price. The developer in this case might
3 decide to postpone construction until prices rise. The utility meanwhile has to decide
4 how to reliably fill the deficit left by a non-performing PURP A contract and is exposed to
5 supply risk and futue price increases.
6 To ensure QF developer obligations are honored, each PURP A contract should
7 have a termination clause enabling the utility to terminate 180 days beyond the
8 committed online date in the contract. This simple provision will put all QF developers
9 on notice that their failure to honor PURP A contract obligations will result in contract
10 termination.
11 Q.When should the liquidated damages deposit be required of the QF
12 developer?
13 A.Recent FERC rulings highight the risk of a PURP A contract constituting
14 a legally enforceable obligation on the utility. This obligation needs to go both ways to
15 ensure both paries honor their commitments. The best way to ensure a level playing
16 field is to require the QF developer to post the liquidated damages deposit at the time that
17 the legally enforceable obligation arises-i.e., when the utility has tendered a contract
18 and the QF developer executes and returs the tendered contract obligating the utility to
19 purchase contract output. Absent this provision, the utilty has the potential to be subject
20 to a legally enforceable obligation without recourse.
21 III
22 III
23 III
Case No. GNR-E-ll-03
Januar 31, 2012
Kalich, C. (Direct)
A vista Corporation
Page 33 of35
1
2
3
4
5
ix. SAR GAS PRICES SHOULD BE UPDATED ANNUALLY USING THE
ENERGY INFORMATION ADMINISTRATION'S ANNUAL ENERGY
OUTLOOK
Q. Do you have any thoughts related to the present SAR natural gas
6 price update cycle?
7 A.Yes. Natural gas is the single largest component of the SAR price
8 calculation. While paries to varous PURP A proceedings before this Commission have
9 strggled to find a fair and timely source for estimating future natural gas prices, they
10 generally agreed that the forecast should be from a public data source. Presently the price
11 is tied to NPCC's work; however, this forecast is not updated with regularity and there is
12 no guarantee that the forecast wil be updated between its once-every-five-years Power
13 Plan. Another source should be used.
14 Q.Do you have a recommended source for an annual update of the
15 natural gas prices?
16 Yes. A better alternative is the Energy Information Administration's ("EIA")
17 Anual Energy Outlook report. This federal government source is published anually
18 and would provide a publicly-available forecast unbiased by anyone with vested interest
19 inPURPA.
20
21
22
23
x.THE COMMISSION SHOULD NOT DETERMINE RECS OWNERSHIP
IN THIS DOCKET
Q. Is Avista taking any position on Renewable Energy Credits (RECs) in
24 this proceeding?
25 A.A vista believes this proceeding should be limited to the SAR and IRP
26 Methodologies, and Avista therefore has limited its testimony accordingly.
27 III
Case No. GNR-E-ll-03
Januar 31, 2012
Kalich, C. (Direct)
A vista Corporation
Page 34 of35
1
2 A.
Q.Does this conclude your direct-filed testimony?
Yes.
Case No. GNR-E-ll-03
Januar 31, 2012
Kalich, C. (Direct)
A vista Corporation
Page 35 of35
CERTIFICATE OF SERVICE
I hereby certify that on this 30th day of January 2012, true and correct copies of
the foregoing Direct Testimony of Clint Kalich were delivered to the following persons
via Email (unless otherwise indicated).
Jean Jewell
Idaho Public Utilities Commission
472 W. Washington St.
Boise, il 83702
Email: jean.jewell(êpuc.idaho.gov
(via Email and Overnight Mail)
Dean J. Miller, Esq.
McDevitt, & Miler, LLP
POBox 2564
Boise, ID 83701-2564
joe(êmcdevitt-miler .com
Daniel E. Solander
Senior Counsel
Rocky Mountain Power
201 S. Main Street, Suite 2300
Salt Lake City, UT 84111
Email: Daniel.solander(êpacificorp.com
Donovan E. Walker
Lisa Nordstrom
Idaho Power Company
POBox 70
Boise, il 83707-0070
Email: dwalker(êidahopower.com
Inordstrom(êidahopower.com
Page I-CERTIFICATE OF SERVICE
Donald L. Howell, II
Krs Sassar
Deputy Attorneys General
Idaho Public Utilities Commission
472 W. Washington St.
Boise, ID 83702
Email: don.howell(êpuc.idaho.gov
krs.sassar(êpuc.idaho .gov
Peter Richardson
Gregory M. Adams
Richardson & O'Leary
515 N. 27th St.
PO Box 72l8Boise, ID 83702
Email: peter(êrichardsonandoleary.com
greg(êrichardsonandoleary.com
Magan Walseth Decker
Senior Staff Counsel
Renewable Northwest Project
917 SW Oak St., Suite 303
Portland, OR 97205
Email: megan(êrnp.org
R. Greg Ferney
Mimura Law Offces, PLLC
2176 E. Franklin Rd., Suite 120
Meridian, il 83642
Email: greg(êmimuralaw.com
Ted S. Sorenson, P.E.
Sorenson Engineering, Inc.
5203 South 11th East
Idaho Falls, il 83404
Email: ted(£sorenson.net
Glenn Ikemoto
Margaret Ruger
Idaho Windfars, LLC
672 Blair Ave.
Piedmont, CA 94611
E-mail: glenni(£envisionwind.com
Margaret(£envisionwind.com
Shelley M. Davis
Barker Rosholt & Simpson, LLP
1010 W. Jefferson St., Ste. 102
P.O. Box 2139
Boise, ID 83701-2139
Email: smd(£idahowaters.com
Ronald L. Wiliams
Williams Bradbury, P.C.
1015 W. Hays St.
Boise il, 83702
Email: ron(£wiliamsbradbur.com
Dana Zentz
VP, Summit Power Group, Inc.
2006 E. Westminster
Spokane, W A 99223
Email: dzentz(£summitpower.com
Page 2-CERTIFICATE OF SERVICE
Robert D. Kah
Executive Director
Northwest and Intermountain Power
Producers Coalition
1117 Minor Ave., Suite 300
Seattle, W A 9810
Email: rkah(£nippc.org
Thomas H. Nelson
Attorney for Renewable Energy Coalition
PO Box 1211
Welches, OR 97067-1211
Email: nelson(£thnelson.com
Bill Piske, Manager
Interconnect Solar Development, LLC
1303 E. Carer
Boise, il 83706
Email: bilpiske(£cableone.net
Bil Brown, Chair
Board of Commissioners of Adams County,
Idaho
POBox 48
Council, il 83612
Email: dbbrown(£frontiernet.net
Scott Montgomery
President, Cedar Creek Wind, LLC
668 Rockwood Drive
North Salt Lake, Uta 84054
Email: scott(£westernenergy.us
Wade Thomas
General Counsel, Dynamis Energy
776 E. Riverside Drive, Suite 15
Eagle, il 83616
Email: wthomas(£dynamisenerg.com
James Carkulis
Managing Member
EXERGY DEVELOPMENT GROUP OF
IDAHO,LLC
802 West Banock Street, Ste. 1200
Boise, Idaho 83702
Email:jcarkulis~exergydevelopment.com
JohnR. Lowe
Consultant to Renewable Energy
Coalition
12050 SW Tremont Street
Portland, OR 97225
Email: jravenesanarcos~yahoo.com
Twin Falls Canal Company
clo Brian Olmstead, General Manager
P.O. Box 326
Twin Falls, Idaho 83303-0326
Email: olmstead~tfcanai.com
Ken Kaufman
Lovinger Kaufman, LLP
825 NE Multnomah, Suite 925
Portland, OR 97232
Email: Kaufman~lklaw.com
Aron F. Jepson
Blue ribbon Energy LLC
10660 South 540 East
Sandy, UT 84070
Email: aronesq~aoi.com
Page 3-CERTIFICATE OF SERVICE
Robert A. Paul
Grand View Solar II
15960 Vista Circle
Desert Hot Springs, CA
Email: robertapaul~gmaii.com
Don Sturtevant
Energy Director
J. R. Simplot Company
ONE CAPITAL CENTER
999 Main Street, P.O. Box 27
Boise, Idaho 83707-0027
Email: don.sturtevant~simplot.com
North Side Canal Company
clo Ted Diehl, General Manager
921 N. Lincoln St.
Jerome, Idaho 83338
Email: nscanal~cableone.net
MJ Humphres
Blue Ribbon Energy LLC
4515 S. Ammon Road
Amon, il 83406
Email: blueribbonenergy~gmaii.com
Mar Lewallen
Clearater Paper Corporation
601 W. Riverside Ave., Suite 1100
Spokane, W A 99201
Email: mar.lewallen~clearwaterpaper.com
Benjamin J. Otto
Idaho Conservation League
710 N. 6th St.
P.O. Box 844
Boise, Idaho 83702
Ph: [phone] x 12
Fax: [phone]
Email: botto(êidahoconservation.org
Page 4-CERTIFICATE OF SERVICE
Ken Miler
Clean Energy Program Director
Snake River Allance
Box 1731
Boise, 1083701
Email: kmiller(êstakeriveralliance.org