HomeMy WebLinkAboutPeseau Testimony.pdf
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE INVESTIGATION)
OF THE CONTINUED REASONABLENESS OF)
CURRENT SIZE LIMITATIONS FOR PURPA) CASE NO. GNR-E-02-1
QF PUBLISHED RATE ELIGIBILITY )
(i.e., 1 MW) AND RESTRICTIONS ON )
CONTRACT LENGTH (i.e., 5 YEARS ) )
)
IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
DENNIS E. PESEAU
PESEAU, DI 1
Idaho Power Company
Q. Please state your name and business address 1
for the record. 2
A. My name is Dennis E. Peseau. My business 3
address is Suite 250, 1500 Liberty Street, S.E., Salem, 4
Oregon 97302. 5
Q. By whom and in what capacity are you 6
employed? 7
A. I am President of Utility Resources, Inc. 8
(URI). URI has consulted on a number of economic, 9
financial and engineering matters for various private and 10
public entities for more than twenty years. 11
Q. Does Exhibit 103 accurately describe your 12
background and experience? 13
A. Yes, although my testimony below expands 14
this information to be more specific as to my participation 15
in Idaho in regard to avoided costs. 16
Q. What is the subject of your direct 17
testimony? 18
A. On July 2, 2002 the Idaho Public Utilities 19
Commission (“the Commission”) issued Order No. 29069, an 20
order on various petitions for reconsideration and motions 21
to stay related to its May 21, 2002 Order No. 29029. Among 22
other things, Order No. 29069 set testimony and hearing 23
PESEAU, DI 2
Idaho Power Company
dates for these proceedings. The Commission indicated that 1
“ . . . [T]he purpose of the hearing is to receive evidence 2
on the reasonableness of the variables in the existing 3
avoided cost rate methodology . . .” [Order No. 29069, Page 4
8.] My testimony will demonstrate that some of the 5
existing variables are no longer reasonable and propose 6
revised variables that will more accurately track future 7
generation costs. 8
Q. Have you computed avoided costs and rates in 9
Idaho previously? 10
A. Yes. I and others in my firm participated 11
in the original PURPA proceedings in Idaho in the early 12
1980s on behalf of the Independent Power Producers of 13
Idaho. We continued to develop avoided cost methodology 14
and policy issues in Idaho until 1997. Our firm has been 15
similarly involved in PURPA avoided cost matters in 16
numerous state jurisdictions and in filings before the 17
FERC. 18
Q. Do you propose changes in the existing 19
avoided cost methodology in your testimony? 20
A. No. As I understand the Commission’s 21
intentions, the purpose of these proceedings is to minimize 22
the time period in which present published rates are stayed 23
PESEAU, DI 3
Idaho Power Company
by addressing only issues that involve an updating of the 1
variables and data necessary to compute avoided costs 2
within the existing methodology. The avoided costs I offer 3
herein continue to be based on the Surrogate Avoided 4
Resource (SAR) as used by this Commission for some time. I 5
will, however, propose enhancements within the SAR method. 6
Q. What conclusions have you reached from your 7
review of the filings in this case? 8
A. I conclude that there are understandable 9
tensions in Idaho at this time between the interests of 10
ratepayers and the interests of potential qualifying 11
facilities (QF) developers. 12
The present proceedings are all about costs 13
and rates. The old assumptions regarding the physical and 14
financial variables inherent in determining avoided cost 15
rates have suddenly become very prominent due to the very 16
high rates produced by the lengthening of available 17
contract terms from five to twenty years. These high rates 18
are shown in Order No. 29057 in Case Nos. AVU-E-02-4, IPC-19
E-02-6, and UPL-E-02-1. Rates this high will undoubtedly 20
attract the attention of the major national and 21
international developer interests. But any avoided cost 22
rates that exceed present utilities’ incremental costs by 23
PESEAU, DI 4
Idaho Power Company
significant amounts would not be in the long-term interests 1
of local QF developers and certainly not ratepayers. 2
However, with the vanishing resource surplus in the West, 3
properly computed avoided cost rates in Idaho and elsewhere 4
should provide for healthy economic climate for QF 5
development. 6
Potential developers naturally view the 7
prospect of very high published rates computed using the 8
past assumptions favorably. Utilities and Staff have 9
raised concerns that these past assumptions will stimulate 10
excess development and much higher rates to ratepayers than 11
if lower cost alternative power sources are acquired. 12
The Commission has acted quickly and 13
responsibly to reconsider the many complex assumptions and 14
variables making up avoided cost estimates in a manner that 15
should not delay developers the timely opportunity to enter 16
into contracts. 17
Q. Do you have a recommendation that might 18
simplify and expedite a resetting of avoided cost rates for 19
these proceedings? 20
A. Yes. At the risk of slightly 21
oversimplifying, I contend that the reason that the current 22
published rates are too high can be attributed almost 23
PESEAU, DI 5
Idaho Power Company
exclusively to two factors: one, a grossly inaccurate 1
estimate of initial natural gas prices and, two, a grossly 2
excessive estimate of natural gas escalation used in 3
computing the levelized fuel component available for “non-4
fueled projects.” 5
I conclude that specific attention and 6
modification of these two factors would provide a 7
reasonable basis for rates for developers wishing to 8
immediately pursue contracts. I recommend that the 9
Commission adjust these two fuel-related variables and set 10
new rates. At that point I would recommend that the 11
Commission expeditiously convene a proceeding during which 12
the Commission could rigorously consider the additional 13
issues that the Commission should evaluate to set accurate 14
avoided cost rates in the new world of open transmission 15
access and deregulated wholesale markets. As some parties 16
have noted, consideration of QF dispatchability, seasonal 17
and daily production characteristics, extent of capacity 18
value and more accurate and flexible quantification of the 19
impact QF resource additions will have on avoided costs is 20
necessary to set a lasting and stable QF environment. 21
These additional enhancements can be 22
considered expeditiously, but not in the accelerated 23
PESEAU, DI 6
Idaho Power Company
schedule set for these proceedings. Below I address the 1
two key fuel-related factors and the remaining list of 2
previous “typical” avoided cost determinants and the rates 3
which result from my recommendations. 4
Q. Why are frequent updates to avoided cost 5
variables necessary? 6
A. Accurate estimates of avoided costs have 7
always been necessary to assure that a proper balance 8
between ratepayers’ interests and qualifying facilities 9
(QFs) is maintained. Avoided cost-based rates that are too 10
high are costly to ratepayers, while avoided cost-based 11
rates that are too low discourage the development of cost 12
effective levels of QF projects. 13
One original intent of PURPA was to 14
encourage some competition between generating resources of 15
regulated electric utilities and outside generating 16
resources. However, with open access and deregulation of 17
wholesale power markets competition among generators to 18
sell to utilities is significantly increased. 19
Perhaps most importantly, frequent updates 20
of avoided costs are necessary because the utility’s 21
marginal or incremental costs upon which avoided costs are 22
based may change frequently, especially in today’s utility 23
PESEAU, DI 7
Idaho Power Company
environment. 1
Q. What are the principal variables affecting a 2
utility’s incremental and avoided costs? 3
A. Under the SAR methodology, the capital and 4
operating costs of the SAR plant, the assumed rates at 5
which capital and operating costs escalate, the forecast 6
date in which the new SAR plant is needed and, finally, the 7
short-term cost or value of short-term surplus energy in 8
years prior to the load/resource deficit are the key 9
factors or variables making up incremental or avoided 10
costs. 11
A more specific list of these key variables 12
was provided by Staff in its May 22, 2002 draft update of 13
avoided costs. I include this list as page 1 of my 14
Exhibit 104 for purposes of discussing the updates that I 15
recommend, along with the updated values I testify to 16
below. 17
Q. When were the values of the variables listed 18
in your Exhibit 104 originally set by this commission? 19
A. With the exception of “current year fuel 20
cost” these values were set prior to 1997. The current 21
year fuel forecast is updated annually, but is tied to 22
average gas prices at Sumas, Washington that are two years 23
PESEAU, DI 8
Idaho Power Company
old. All of the variables used in establishing the SAR 1
avoided costs are clearly in need of review. 2
Q. How will your review of necessary variable 3
updates proceed? 4
A. I will follow generally the list of 5
variables in my Exhibit 104. However, I will attempt to 6
address each variable in descending order of importance in 7
the calculation of avoided costs. Far and away the most 8
important variables in determining today’s avoided costs 9
are today’s actual natural gas prices delivered to the SAR 10
combined cycle combustion turbine (CCCT) and, for the non-11
fueled levelized rate option, the escalation rate assumed 12
today for the delivered natural gas price over the life of 13
the QF contract. 14
NATURAL GAS PRICES 15
Q. Why is the “current year fuel cost” such a 16
large and important variable in determining avoided costs? 17
A. The SAR is presumed to be a Combined Cycle 18
Combustion Turbine (CCCT). This technology is relatively 19
capital efficient in that these plants are capable of being 20
operated at very high capacity factors and have relatively 21
low capital costs. Fuel and associated variable costs, 22
here natural gas, will typically comprise more than two-23
PESEAU, DI 9
Idaho Power Company
thirds of total power costs making up avoided costs. 1
Therefore, the SAR natural gas cost adopted for purposes of 2
estimating avoided costs must be indicative of what the 3
utility would pay in the particular year the CCCT is 4
assumed to be brought on line. 5
Q. What is the price of natural gas delivered 6
to the CCCT assumed to be in the proposed 2002-2003 avoided 7
cost update? 8
A. As pointed out by staff in its June 25, 2002 9
Supplemental Answer, 10
. . . At the present time, the starting fuel price 11
subject to 6% escalation over the life of contracts signed 12
or requested this year is $4.82 per MMBtu. This price will 13
increase to $5.23 in July if approved by the Commission. 14
Under any other gas price methodology such as historical 15
averages, historical trend lines or future market 16
projections, the resulting avoided costs would be 17
significantly below that using the existing methodology 18
. . . 19
[Staff Supplemental Answer, Page 3.] 20
Failure to update the gas price assumption to 21
reflect actual natural gas prices today will result in the 22
use of a $5.23 per MMBtu gas price as the basis for 23
PESEAU, DI 10
Idaho Power Company
computing the adjustable avoided cost rate for fueled 1
rates, contracts and as the initial rate to be escalated 2
for non-fueled rate contracts. 3
Q. Is the $5.23 per MMBtu natural gas price a 4
reasonable assumption today? 5
A. No. For example, at the time of the writing 6
of this testimony, the Sumas, Washington natural gas price, 7
adjusted for delivery into Idaho on Northwest Pipeline is 8
approximately $1.86 MMBtu ($1.51 border price, plus $.35). 9
Use of the $5.23 figure for purposes of setting avoided 10
costs for both fueled and non-fueled contracts would be 11
very detrimental to ratepayers and is not in the public 12
interest. 13
Q. What adjustments to the assumed natural gas 14
price are necessary in order to reflect current and likely 15
annual 2002-2003 prices? 16
A. The base price of natural gas delivered to 17
Idaho should be reset to $2.79 per MMBtu for purposes of 18
estimating avoided cost rates. 19
Q. How did you determine a natural gas price of 20
$2.79 per MMBtu? 21
A. I began with a review of the daily firm 22
prices of natural gas transactions at Sumas, Washington. 23
PESEAU, DI 11
Idaho Power Company
Sumas is the trading center that has been used recently for 1
indexing natural gas prices for avoided costs in Idaho. 2
Attached as my Exhibit 105 is a copy of daily recorded 3
transactions at Sumas for the year ending July 17, 2002. 4
Although average prices at Sumas during this period were as 5
low as $1.08 per MMBtu and as high as $3.43 per MMBtu, the 6
vast majority of gas sales were at prices that ranged 7
between $1.80-2.70 per MMBtu. I note that, consistent with 8
other forecasts, the trend in gas prices was downward from 9
July 2001-July 2002. 10
Q. What is the average cost of delivering gas 11
from Sumas to Idaho? 12
A. The firm transportation rates for delivery 13
from either Sumas or the Rockies on Northwest Pipeline are 14
approximately $.35 per MMBtu. 15
Q. What information and forecasts did you 16
review in your concluding on the $2.79 per MMBtu? 17
A. In addition to the most recent gas prices at 18
Sumas, Washington I analyzed the April 25, 2002 Draft Fuel 19
Price Forecasts for the 5th Northwest Conservation and 20
Electric Power Plan published by the Northwest Power 21
Planning Council. Although this document, which I attach 22
as my Exhibit 106, is a draft, it is very similar to the 23
PESEAU, DI 12
Idaho Power Company
Council’s methods and forecasts used in its 4th Plan. In 1
addition, most of the natural gas commodity price, 2
transportation, well-head price and regional basis 3
differential data are simply taken from established and 4
reputable forecasting and data processing organizations. 5
A review of the Council’s 5th Plan supported 6
my recommended gas price of $2.79 per MMBtu. 7
Q. How do other forecasting organizations’ 8
natural gas price forecasts compare with your recommended 9
$2.79 per MMBtu? 10
A. I reviewed the 2002-2003 U.S. wellhead 11
natural gas price forecast for the U.S. Energy Information 12
Administration, the Gas Research Institute, the draft 13
California Energy Commission and the DRI-WEFA forecast. 14
These institutions forecast national wellhead gas prices in 15
the range of $2.60-$2.90 per MMBtu. National wellhead 16
prices have a basis differential that is higher than Sumas 17
by $.35-.45 per MMBtu. That is, these national wellhead 18
prices must be reduced by $.35-.45 per MMBtu to be made 19
into a comparable Sumas, Washington gas price forecast. 20
These forecasts are summarized in the Council’s 5th Plan. 21
Q. Exactly how did you reach a recommended 22
price of $2.79 per MMBtu delivered to Idaho? 23
PESEAU, DI 13
Idaho Power Company
A. In order to reduce these ranges of prices to 1
a single price, I averaged the 2002 and 2003 gas price 2
forecasts for Pacific Northwest natural gas prices for 3
regional utilities. The 2002 gas price of $2.53 and the 4
2003 gas price of $3.04 per MMBtu can be found on Page F-1, 5
Appendix C of my Exhibit 106. The simple average of these 6
prices is $2.79, which I recommend be used as the base gas 7
price for purposes of setting avoided cost rates in these 8
proceedings. 9
Q. Aren’t “forward price” curves available from 10
which the 2002-2003 Idaho natural gas prices could be 11
predicted? 12
A. Yes. However, these forward price quotes 13
are somewhat volatile. For example, I received a forward 14
price on Platt’s Gas Daily today (July 18, 2002) for July 15
2002-July 2003 for $1.90 flat from Sumas and $1.26 flat 16
from the Rockies, both deliverable to Idaho for an 17
additional $.35 per MMBtu. Given potential volatility, I 18
continue to recommend the price of $2.79 per MMBtu. 19
Q. What is the significance of the second 20
natural gas price factor you alluded to above, the 21
escalation rate to be used for multi-year non-fueled 22
projects? 23
PESEAU, DI 14
Idaho Power Company
A. Both fueled and non-fueled projects are 1
entitled to rates containing a levelized capacity cost 2
component. Non-fueled projects are entitled to a rate 3
which also contains a levelized fuel component. Since the 4
effect of levelizing the fuel component is to lock in an 5
assumed rate of inflation and “front-end” load this assumed 6
inflation over the life of the contract, it is very 7
important to use a realistic rate. Staff’s Supplemental 8
Answer, Pages 2-3 discusses the significant impact that the 9
fuel price escalator has upon non-fueled levelized rates. 10
Q. What fuel price escalator has been used 11
recently for purposes of computing non-fueled project 12
rates? 13
A. 6%. 14
Q. Is a 6% assumed escalation rate for natural 15
gas a reliable escalator for today’s or near-term future 16
gas prices? 17
A. No. In fact retail gas prices in the 18
Pacific Northwest have generally been flat since the late 19
1980s, rising only moderately. The one notable exception 20
to this relative price stability was, as we are all 21
painfully aware, the huge natural gas (and electric) price 22
runup from fall 2000 to spring 2001. Any simple trending 23
PESEAU, DI 15
Idaho Power Company
or averaging technique used to attempt to forecast price 1
escalation will be unduly influenced by this market 2
aberration. The actual cause of this unpredicted price 3
runup remains the subject of numerous lawsuits and 4
regulatory inquiries in the western U.S. 5
Q. Do you have a specific natural gas price 6
escalation rate that you recommend be used in these 7
proceedings for purposes of the levelized fuel component 8
for non-fueled contract rates? 9
A. Yes. For the most part, natural gas 10
forecasts show little or no “real” escalation. That is, 11
gas prices are predicted to escalate at near the general 12
rate of inflation. For example, the Northwest Power 13
Planning Council report referenced above shows forecasts of 14
escalation rates of about .5% in real terms. 15
Upon review of Idaho Power’s 2002 IRP, I 16
noted that the WEFA Group’s long-term gas escalator is 17
2.62% nominal. For purposes of estimating avoided cost 18
rates for non-fueled contracts this year, I recommend that 19
the escalation variable be changed from the previous 6% to 20
2.62%. For each subsequent update, I strongly recommend an 21
updating of this variable. 22
Q. You indicated previously that the two 23
PESEAU, DI 16
Idaho Power Company
variables you have just discussed, the initial base natural 1
gas price and the rate at which it escalates for non-fueled 2
contracts, are most crucial for this abbreviated 3
proceeding. Are you prepared to discuss other variable 4
updates? 5
A. Yes. Again I believe the two variables 6
above to be most important for purposes of setting an 7
immediate or interim rate. For determining an update on 8
certain of the engineering, operating and cost data, Idaho 9
Power has retained the firm of Parsons Brinckerhoff. This 10
firm has provided me with the following SAR variables: 11
SAR Plant Life 12
SAR Plant Cost 13
SAR Capacity Factor 14
SAR Fixed O&M 15
SAR Variable O&M 16
The values for these variables and the base 17
natural gas cost and escalation rate I just recommended are 18
summarized in my Exhibit 104, along with the variable 19
values I now discuss. 20
PESEAU, DI 17
Idaho Power Company
FIRST YEAR DEFICIT 1
Q. Why is the first year of generating resource 2
deficit an important variable for computing avoided costs? 3
A. Under the SAR methodology, the avoided cost 4
rate is computed as a surplus energy value for the 5
immediate years in which the utility is surplus and a full 6
capacity and energy value for the SAR from the first year 7
of resource deficit forward. As the capacity and energy 8
value of the SAR together is generally greater than the 9
value of surplus energy, different assumptions on the year 10
of the deficit will alter the levelized avoided cost. I 11
note, however, that under the assumptions for surplus 12
energy values used in this case, the deficit year issue is 13
not very significant. 14
Q. What is the period you recommend as that 15
Idaho power shows the need for new permanent resources? 16
A. The year 2005. Idaho Power’s IRP indicates 17
that the Company will require additional permanent 18
resources beginning in June 2005 (IRP Page 4). There are 19
limited peak deficits prior to 2005. Under poorer than 20
median water conditions and greater than expected loads, 21
small monthly energy deficits between in 2004. 22
Accelerating the first deficit year by one year makes only 23
PESEAU, DI 18
Idaho Power Company
a one mill difference in a twenty year non-fueled contract. 1
SURPLUS ENERGY COSTS 2
Q. What surplus energy cost do you use to 3
compute avoided costs? 4
A. I use a 2002 base year surplus energy cost 5
of 28.28 mills/kWh, escalated at 5.90% annually. 6
CURRENT YEAR FUEL COST 7
Q. What value do you use to measure the current 8
year fuel cost? 9
A. The current year fuel cost is determined by 10
multiplying my $2.79 per MMBtu, 2002-2003 natural gas fuel 11
cost by the SAR heat rate of 6994 Btu/kWh. This results in 12
a current year fuel cost of 19.51 mills/kWh. 13
UNCHANGED VARIABLES 14
Q. Have some of the variables used in the 15
computing of avoided costs remained unchanged? 16
A. Yes. Some of the variables, such as the 17
utility’s weighted cost of capital, ratepayer discount rate 18
and capital carrying charge rate, remain the same as by 19
prior Commission approval. 20
The remaining unchanged variable, the SAR 21
plant life, is still thirty years as the CCCT technology is 22
essentially unchanged. 23
PESEAU, DI 19
Idaho Power Company
SEASONALIZATION OF AVOIDED COSTS 1
Q. What is the issue with respect to the 2
seasonalization of avoided costs? 3
A. The calculation of avoided costs is based on 4
the utility’s incremental or marginal costs. As is true 5
for many utilities, and is particularly true for Idaho 6
Power, incremental capacity and energy costs vary by 7
season. To the extent that avoided costs rates are also 8
seasonalized, QF projects that produce power during months 9
in which Idaho Power experiences high loads and/or high 10
costs will receive higher published rates. This is a very 11
positive cost-based incentive for QFs and a means to 12
minimize ratepayers’ revenue requirement. 13
This is recognized currently in Staff’s 14
avoided cost methodology program, although the 15
seasonalization factors are currently set to zero. In an 16
effort to reward appropriate QF technologies, particularly 17
QFs that should be able to some extent shape their 18
production such as anaerobic digesters, the existing 19
seasonalization factors approved by the Commission in Idaho 20
Power’s last incremental cost study should continue to be 21
reflected in published avoided cost rates. 22
Q. Is the use of seasonalized published rates 23
PESEAU, DI 20
Idaho Power Company
in accord with sections 201 and 210 of PURPA? 1
A. Yes. The essential concept expressed by the 2
FERC was that of calculating avoided cost-based rates in 3
accordance with the incremental cost of the utility “but 4
for” the purchase from the QF. Prior rate cases, and rates 5
to ratepayers approved by the Commission clearly establish 6
that Idaho Power’s incremental costs vary by season. 7
Furthermore, in my opinion, seasonalized avoided cost rates 8
better conform to rates that are just and reasonable to 9
Idaho Power’s ratepayers, and would eliminate any 10
discrimination against QFs because rates paid to them would 11
be in stricter accordance with incremental costs. 12
Q. Were prior published QF rates seasonalized? 13
A. Yes, my understanding is that seasonalized 14
rates have been approved by the Commission for Idaho Power. 15
Q. What are the presently approved 16
seasonalization factors of Idaho Power? 17
A. The factors are as follows: .735 for March 18
through May, 1.2 for June through September, and 1.0 19
October through February, as established in Commission 20
Order No. 20350. These, or updated seasonal factors, 21
should continue to be used to avoid cost payments. 22
Q. Do you have concluding remarks? 23
PESEAU, DI 21
Idaho Power Company
A. Yes. As we enter a period of need for 1
additional resources, certain other aspects of QF contracts 2
may need to be considered. Topics I mentioned at the 3
outset of my testimony include dispatchability, a review of 4
seasonal factors, contribution to capacity at peak, and 5
load/resource balances. The intent of considering these 6
factors would be to add certainty and value for the QF 7
projects most capable of contributing to the operating 8
needs of Idaho Power. A quick resolution of the base fuel 9
rate and fuel escalator issues with the setting of rates 10
based on updating these two key variables would provide 11
additional breathing room in which to consider these other 12
important considerations. 13
Q. Does this conclude your direct testimony? 14
A. Yes, it does. 15