20120629Sterling Rebuttal.pdf

BEFORE THE
2012JU29 PM 14:142
A.L1O
IDAHO PUBLIC UTILITIES COMMISSION
COMSION
IN THE MATTER OF THE COMMISSION'S
REVIEW OF PURPA QF CONTRACT
PROVISIONS INCLUDING THE SURROGATE
AVOIDED RESOURCE (SAR) AND
INTEGRATED RESOURCE PLANNING (IRP)
METHODOLOGIES FOR CALCULATING
PUBLISHED AVOIDED COAT RATES.
CASE NO. GNR-E-11-03
REBUTTAL TESTIMONY OF RICK STERLING
IDAHO PUBLIC UTILITIES COMMISSION
JUNE 29, 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. Are you the same Rick Sterling who previously
9 submitted testimony in this proceeding?
10 A. Yes, I am.
11 Q. What is the purpose of your rebuttal testimony
12 in this proceeding?
13 A. The purpose of my rebuttal testimony is to
14 address the direct testimony of Richard Guy of Idaho Wind
15 Partners I, LLC and the direct testimony of Don
16 Schoenbeck, witness for the Twin Falls and North Side
17 Canal Companies and the Renewable Energy Coalition as
18 their testimonies relate to 18 C.F.R. 292.304(f)
19 ("Section 304(f)"), the FERC rule implementing PURPA that
20 deals with curtailment under certain circumstances.
21 Q. Do you agree with Mr. Guy's and Mr.
22 Schoenbeck's interpretations of Section 304(f)?
23 A. No, I do not.
24 Q. Please explain why you believe their
25 interpretations of Section 304(f) are incorrect.
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A. On pages 4-6 of Mr. Guy's testimony, he
discusses Section 304(f) and states that it is his
understanding, based on FERC Order No. 69, that Section
304(f) does not apply to QF contracts with fixed rates.
Similarly, Don Schoenbeck, on pages 36-42 of his direct
testimony, also contends that Idaho Power's proposed
Schedule 74 is not consistent with FERC's view on QF
curtailment.
For reference, 18 CFR 292.304(f) states the
following:
(f) Periods during which purchases not
required. (1) Any electric utility which
gives notice pursuant to paragraph (f)
(2) of this section will not be required
to purchase electric energy or capacity
during any period during which, due to
operational circumstances, purchases from
qualifying facilities will result in costs
greater than those which the utility would
incur if it did not make such purchases,
but instead generated an equivalent amount
of energy itself. 1
FERC's Order No. 69, in explaining the intent
of Section 304(f), stated the following:
The Commission does not intend that this
paragraph override contractual or other
legally enforceable obligations incurred
by the electric utility to purchase from a
qualifying facility. In such
arrangements, the established rate is
based on the recognition that the value of
1 (Parts (2), (3), and (4) of this section have been omitted
because they relate to notification requirements not relevant
to this discussion).
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the purchase will vary with the changes in
the utility's operating costs. These
variations ordinarily are taken into
account, and the resulting rate represents
the average value of the purchase over the
duration of the obligation. The
occurrence of such periods may similarly
be taken into account in determining rates
for purchases.2
A. Just recently, FERC went on to further explain
the proper application of Section 304(f) when it stated
the following:
55.In Order No. 69, which implemented
section 304(f), the Commission stated that
that section was intended to deal with a
certain condition which can occur during
light loading periods, in which a utility
operating only base load units would be
forced to cut back output from the units
in order to accommodate the unscheduled QF
energy purchases. The Commission stated
that such base load units might not be
able to later increase their output levels
rapidly when the system demand later
increased, resulting in the utility
needing to rely upon less efficient,
higher cost units. Section 304(f), when
read in conjunction with the relevant
explanation in Order No. 69, applies only
to such low loading scenarios, and cannot
be relied upon to curtail purchases of
unscheduled QF energy for general economic
reasons.
56.Many avoided cost rates are calculated
on an average or composite basis, and
already reflect the variations in the
value of the purchase in the lower overall
rate. In such circumstances, the utility
is already compensated, through the lower
rate it generally pays for unscheduled QF
2 FERC Order No. 69, Docket No. RM79-55, Final Rule Regarding the
Implementation of Section 210 of the Public Utility Regulatory
Policies Act of 1978, (Issued February 19, 1980), p. 77.
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energy, for any periods during which it
purchases unscheduled QF energy even
though that energy's value is lower than
the true avoided cost. On the other hand,
for avoided cost rates that are determined
in real-time, such avoided costs adjust to
reflect the low (or zero or negative)
value of the unscheduled QF energy,
allowing the QF to make its own
curtailment decisions. In neither case is
the utility authorized to curtail the QF
purchase unilaterally.3
It is noteworthy that FERC, in paragraph 55 of the
Entergy Order recognized that "Many avoided cost rates
are calculated on an average or composite basis, and
already reflect the variations in the value of the
purchase in the lower overall rate." (Emphasis added).
Furthermore, FERC stated "In such circumstances, the
utility is already compensated, through the lower rate it
generally pays for unscheduled QF energy, for any periods
during which it purchases unscheduled QF energy even
though that energy's value is lower than the true avoided
cost." (Emphasis added).
Mr. Guy's and Mr. Schoenbeck's interpretations
of the proper application of Section 304(f) might be
correct if the presumptions described by FERC in Order
No. 69 and in the Entergy order were correct for Idaho.
However, those presumptions, in fact, are not correct
Entergy Services, Inc., Docket Nos. ER05-1065--011, 0A07-32-008;
137 FERC ¶ 61199 (F.E.R.C.) Order on Compliance Filing (Issued
December 15, 2011).
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for Idaho.
2 I have been the person responsible for
3 computing Idaho's published avoided cost rates for the
4 past 18 years. Although I did not create the original
5 SAR model used to compute published avoided cost rates, I
6 have made the extensive changes to the model that have
7 been ordered over the past 18 years, I have maintained
8 the model, and I have been responsible for making all of
9 the avoided cost computations adopted by the Commission
10 since 1995. Based on my extensive experience with the
n SAR model, Idaho's published avoided cost rates do not
12 already reflect the variations in the value of the
13 purchase in the lower overall rate during the specific
14 low loading scenarios when 304(f) is clearly intended to
15 apply.
16 It is true that Idaho's avoided cost rates may
17 at times be either higher or lower than the true avoided
18 costs, but this is due to real-time prices not exactly
19 matching rates computed in advance for a long-term
20 contract. This fact is simply an unavoidable outcome of
21 the computation methodology, not an input assumption that
22 explicitly drives the result. Frequent deviations
23 between real-time prices and computed long-term avoided
24 cost rates are inevitable under any computation
25 methodology, regardless of whether any attempt is made to
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a. account for low loading scenarios.
2 Under the SAR methodology for computing
3 published avoided cost rates, the method is based solely
4 on the estimated cost of building and operating a CCCT,
5 the surrogate avoided resource. There is clearly no
6 attempt to model low loading scenarios, or for that
7 matter, any other load scenarios. Furthermore, there is
8 no consideration for operational circumstances or
9 constraints of either the QF or the utility's other
10 generation resources, nor is there any attempt to reflect
11 actual variations in the value of the purchase in a lower
12 overall rate. Quite simply, the SAR methodology
13 considers only the CCCT surrogate, independent of any
14 other resources and system conditions, and assumes that
15 it will be operated during all hours when it is
16 available.
17 All 11 of the projects owned and operated by
18 Idaho Wind Partners have contracts containing published
19 avoided cost rates computed using the SAR methodology.
20 Therefore, there is no consideration in the rates in any
21 of these contracts for low loading conditions when
22 curtailment would be likely.
23 Q. Once avoided cost rates have been computed by
24 the SAR model, are there post-modeling adjustments
25 applied to the rates to attempt to shape them to better
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i match variations in true avoided costs?
2 A. Yes, two types of adjustments are made. One
3 adjustment is made to shape the rates by season and the
4 other adjustment is made to shape the rates based on
5 heavy and light load hours.
6 Q. Please explain the seasonal adjustment.
7 A. The avoided cost rates computed by the SAR
8 model consist of single annual values corresponding to
9 each year of the proposed contract. The purpose of
10 seasonal rate adjustments is to shape annual rates into
11 seasonal rates that better reflect variations in value
12 during different times of the year. For example, power
13 is typically more valuable during peak summer and winter
14 months, and less valuable during spring months when hydro
15 generation is cheap and plentiful. Seasonalization
16 factors are applied to the avoided cost rates computed by
17 the SAR model to either increase or decrease the rates
18 during different seasons. Seasonalization factors are
19 applied as weighting factors. For Idaho Power for
20 example, a seasonalization factor of 1.20 is applied in
21 the months of July, August, November and December,
22 thereby increasing rates by 20 percent in the utility's
23 summer and winter peak load months. Conversely, in the
24 months of March - May, a seasonalization factor of 0.735
25 is applied to lower avoided costs during the spring
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1 runoff period. During the remaining months of the year
2 (January, February, June, September and October), a
3 seasonalization factor of 1.00 is applied. For Avista,
4 seasonalization factors are applied in only two different
5 seasons of the year. For PacifiCorp, seasonalization
6 factors are applied monthly.
7 Q. Please explain the heavy and light load hour
8 adjustment.
9 A. The purpose of the heavy and light load hour
10 adjustment is to shape seasonal (or monthly) rates into
11 hourly rates that better reflect variations in value
12 during different times of the day. Heavy load hours are
13 those hours from 7:00 am through 11:00 pm Monday through
14 Saturday. Light load hours are the remaining nighttime
15 hours and all hours on Sundays and holidays. A
16 Commission-approved differential between heavy and light
17 load hour prices is applied to rates calculated by the
18 SAR model such that prices in heavy load hours are
19 increased and prices in light load hours are decreased.
20 There is no overall impact of the heavy/light load price
21 differential on projects with the same flat hourly
22 generation shape; however, facilities that produce more
23 or less of their generation in heavy or light load hours
24 receive payments accordingly. The current approved
25 heavy/light load hour price differential is $5.00 per MWh
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i for Avista, $7.28 for Idaho Power, and varies on a
2 monthly basis for PacifiCorp.
3 Q. Do either of the seasonal adjustments or the
4 heavy/light load hour adjustments account for the type of
5 variation in price or the low load scenarios contemplated
6 by the Entergy Order?
7 A. No, they do not. The seasonal and heavy/light
8 load hour adjustments are solely intended to recognize
9 that the value of power generally varies throughout the
months of the year and throughout the hours of the day.
11 Because the SAR model only computes annual rates, both of
12 these adjustments help to shape the rates to more closely
13 match expected variation in actual market prices.
14 Clearly, however, they do not consider the dispatch of
15 any of the utility's resources, the actual real-time
16 variations in the value of power, or the utility's
17 inability to further back down base load resources or its
18 ability to ramp them back up to meet increasing load. In
19 short, these adjustments are in no way intended to
20 address pricing during those low load situations when the
21 utility might be forced to curtail generation.
22 Q. Are there any other adjustments that are made
23 to the avoided cost rates computed by the SAR model?
24 A. Yes, there is one additional adjustment that is
25 applied only to wind projects. That adjustment is a wind
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a. integration adjustment that serves to decrease avoided
2 cost rates for intermittent wind generation. The purpose
3 of the wind integration adjustment is to account for the
4 additional costs experienced by the utility when it must
5 integrate wind generation with the generation produced by
6 its other generation resources. The additional costs
7 attributable to intermittent wind generation are
8 primarily the result of non-economic dispatch of the
9 utility's other resources. Wind integration costs
10 adopted by the Commission vary from seven to nine percent
11 of the avoided cost rate depending on the level of wind
12 penetration on each utility's system, and are capped at
13 $6.50 per MWh.
14 Q. Do wind integration adjustments account for the
15 type of variation in price contemplated by the Entergy
16 Order?
17 A. No, they do not. Wind integration adjustments
18 are generally determined through sophisticated studies
19 that measure the additional incremental costs incurred by
20 the utility as increasing amounts of wind generation are
21 added to the system. The studies typically involve
22 hourly dispatch modeling of the utility's entire resource
23 portfolio. The hourly dispatch simulations attempt to
24 replicate normally expected conditions, not extreme low
25 load circumstances when all base load resources are
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1 backed down to minimum levels. In fact, the hourly
2 dispatch models typically used for wind integration
3 studies do not have the ability to curtail QFs.
4 Therefore, wind integration adjustments do not account
5 for the type of variation in price and the low load
6 scenarios contemplated by the Entergy Order.
7 Q. Eight of the eleven Idaho Wind Partners
8 contracts contain what is sometimes referred to as the
9 "90/110" provision. Can you explain what this provision
10 is and whether it relates to price variations
11 contemplated by the Entergy Order?
12 A. The 90/110 rule was adopted in 2004 when the
13 first large scale wind QF contracts were proposed. With
14 the emergence of large wind projects, a question arose
15 about whether wind facilities, because of their
16 intermittent generation, should be entitled to published
17 avoided cost rates. Up until this time, utilities had
18 held that published rates were intended for "firm"
19 generation that was reasonably predictable. As a
20 condition for being eligible for published rates, the
21 utilities proposed that the generation from all new
22 facilities be subject to a requirement that the monthly
23 generation be predictable within a 90 to 110 percent
24
25
Case Nos. IPC-E-04-08 and IPC-E-04-10, Order No. 29632, November
22, 2004.
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band. If the project could deliver an amount of energy
2 that was at least 90 percent of its monthly estimate but
3 not more than 110 percent of the estimate, it was
4 entitled to full published avoided cost rates. However,
5 if the facility's actual monthly generation fell outside
6 of the 90/110 percent band, it would be entitled to a
7 market-based rate for the shortfall or the excess
8 generation. The purpose of the 90/110 rule was to
9 require a reasonable level of predictability for QFs,
10 comparable to the predictability a utility could expect
11 if it purchased power from some other source.
12 The 90/110 rule was later abandoned for wind
13 projects and replaced with three new requirements
14 intended to accomplish a similar goal. Three of Idaho
15 Wind Partners' eleven projects contain these new
16 requirements. Under the new requirements, in order to be
17 eligible for published rates, wind projects must maintain
18 a "Mechanical Availability Guarantee" of 85 percent, must
19 agree to pay a proportionate share of wind forecasting
20 costs, and must agree to a wind integration charge as
21 discussed earlier. As with the 90/110 rule, these three
22 new requirements are intended to ensure a reasonable
23 level of predictability in order for wind projects to be
24 entitled to "firm" or published avoided cost rates. The
25 purpose of these requirements is not to account for the
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1 type of variation in price based on curtailment
2 contemplated by the Entergy Order.
3 Q. What can you conclude about curtailment from
4 the way published rates are calculated and from the other
5 elements contained in the power sales agreements?
6 A. I conclude that nothing in the SAR model in any
7 way captures the variations in an overall rate that would
8 encompass circumstances described in FERC Order 69 or in
9 the Entergy Order. Furthermore, none of the provisions
10 contained in any of the Idaho Wind Partners' contracts
11 (or any other QF contracts) address or capture variations
12 in an overall rate that would encompass circumstances
13 described in FERC Order 69 or in the Entergy Order.
14 Q. Could the SAR model be modified to consider the
low load scenarios described in FERC Order 69?
16 A. No, I do not believe that it could be.
17 Modeling load scenarios would require far more
18 sophistication than the current SAR model possesses. An
19 SAR model, because it is based on the costs of building
20 an operating a single, surrogate resource, is not capable
21 of considering load scenarios. I believe that it would
22 be necessary to have a model with resource dispatch
23 capability in order to model various load scenarios.
24 Q. Does this conclude your rebuttal testimony?
25 A. Yes, it does.
CASE NO. GNR-E-11-03 STERLING, R (Reb) 13
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CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 29TH DAY OF JUNE 2012,
SERVED THE FOREGOING REBUTTAL TESTIMONY OF RICK STERLING, IN
CASE NO. GNR-E-11-03, BY E-MAILING AND MAILING A COPY THEREOF,
POSTAGE PREPAID, TO THE FOLLOWING:
DONOVAN E WALKER
JASON B WILLIAMS
IDAHO POWER COMPANY
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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
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GRAND VIEW SOLAR II
15690 VISTA CIRCLE
DESERT HOT SPRINGS CA 92241
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RENEWABLE ENERGY COALITION
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WELCHES OR 97067
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MIMURA LAW OFFICES PLLC
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STE 120
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DANIEL E SOLANDER
TED WESTON
ROCKY MOUNTAIN POWER
201 S MAIN ST STE 2300
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PETER J RICHARDSON
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RICHARDSON & O'LEARY
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ENERGY DIRECTOR
J R SIMPLOT COMPANY
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JAMES CARKULIS
EXERGY DEVELOPMENT GROUP OF
IDAHO LLC
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BOISE ID 83702
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RENEWABLE ENERGY COALITION
12050 SW TREMONT ST
PORTLAND OR 97225
BILL PISKE MGR
INTERCONNECT SOLAR
DEVELOPMENT LLC
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WILLIAMS BRADBURY DYNAMIS ENERGY LLC
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TED S SORENSON P E GLENN IKEMOTO
BIRCH POWER COMPANY MARGARET RUEGER
5203 SOUTH 11TH EAST IDAHO WINDFARMS LLC
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KEN MILLER MARV LEWALLEN
SNAKE RIVER ALLIANCE CLEAR WATER PAPER CORP
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SPOKANE WA 99201
ENERGY INTEGRITY PROJECT
TAUNA CHRISTENSEN
769N 1100
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