20150423Sterling Direct.pdf

BEFORE THE
1 ':I: :lJl i ''":l'S
IIDAHO PUBLIC UTILITIES GOMMISSION
IN THE MATTER OF IDAHO POWER
COMPANY'S PETITION TO MODIFY
TERMS AND CONDITIONS OF
PU RPA PURCHASE AGREEMENTS
IN THE MATTER OF AVISTA
CORPORATION'S PETITION TO
MODIFY TERMS AND CONDITIONS
OF PURPA PURCHASE
AGREEMENTS
IN THE MATTER OF ROCKY
MOUNTAIN POWER COMPANY'S
PETITION TO MODIFY TERMS AND
CONDITIONS OF PURPA
PURCHASE AGREEMENTS
CASE NO. |PC-E-15-01
CASE NO. AVU.E.15.O1
GASE NO. PAC-E-{ 5-03
DIRECT TESTIMONY OF RIGK STERLING
IDAHO PUBLIC UTILITIES COMMISSION
APRTL 23,2015
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O. Please state your name and business address for
the record.
A. My name is Rick Sterling. My business address
is 472 West Washington St,reet, Boise, Idaho.
O. By whom are you employed and in what capacity?
A. r am employed by the Tdaho Pub1ic Utilities
Commission as the Engineering Supervisor.
O. What is your educational and professional
background?
A. I received a Bachelor of Science degree in Civil
Engineering from the University of Idaho in 1981 and a
Master of Science degree in Civil Engineering from the
University of Idaho in 1983. f worked for the fdaho
Department of Water Resources Energy Divisj-on from 1983 to
1,994. In 1988, I became licensed in Idaho as a registered
professional Civil Engineer. I began working at the Idaho
Public Utilities Commj-ssion in 1994. My duties at the
Commission j-nclude analysis of a wide variety of electric
and large water utility applicat,ions. I have been the
lead st.aff member on all Publ-ic Utility Regulatory
Policj-es Act (PURPA) dockets at the Commission sj-nce a994.
In additj-on, I lead the Engineering Section and supervise
a st.aff of engineers and utility analysts.
a. What is the purpose of your testimony in this
proceeding?
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STERLING, R. (Di) ]-
STAFF
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A. The purpose of my testimony is to address the
petition of Idaho Power to reduce the maximum contract
length for IRP-based (Integrated Resource Plan) PURPA
contracts from the currenL 20 years to two years. I will
also address similar requests by Avista and PacifiCorp for
reduced contract lengths. In addition, I will make
recommendations for maximum contract length for SAR-based
(Surrogate Avoided Resource) PURPA contracts, including
replacement contracts .
a. What do you belj-eve is the real issue that needs
to be addressed in t.his case?
A. I believe the real issue ls the risk exposure to
ratepayers that can occur due to long-term PURPA
contracts. Long-Lerm contracts, by themselves, would not
necessarily be problematic if the long-term avoided cost
rates contained in those contracts fairly represented
avoided costs over the entire duration of the contract.
Unfortunately, however, I do not believe any avoided cost
calculation can prove to remain accurate over a 21-year
period. Absent any mechanism to periodically adjust
avoided cost raLes throughout the term of the contract,
shorter contract lengths appear to be one of the only
viable and effective ways to reduce the risk exposure to
ratepayers.
O. Why don't you believe avoided cost calculatj-ons
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can prove to remain accurate over a 2l-year period?
A. Under the IRP method, avoided cost rates are
computed, in large part, using an hourly dispatch model
that dispatches generation to meet load in each hour at
the lowest possible cost. The dispatch models require
extensive information about each of the generation plants,
typically throughout the western U.S., as well as long-
term forecasts of loads and fuel prices. While forecasts
can be prepared and assumptions can be made easily enough,
it is extremel-y unlikely t.hat those forecasts and
assumptions will remain accurate over a long period of
time. Consequently, it is equally unlikely that the
avoided cost rates that emerge from the dispatch models
will remain accurate. It is possible that the avoided
cost rates will be too high at some times and too 1ow at
other tj-mes. It is also possible, however, that the
avoided cost rates will be too high or too 1ow throughout
the entire contract length. Regardless of whether the
avoj-ded cost rates are too high or too 1ow, 100 percent of
the risk of actual prices deviating from forecasEed
avoided cost raLes is borne by ratepayers and none of the
risk is borne by QFs.
O. Has the Commlssion Staff taken a position
recently on maxj-mum contract length for PURPA contracts?
A. Yes, in Case No. GNR-E-11-03, I recommended t.hat
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the Commissj-on reduce maximum contract length to five
years for contracts containing rates computed under the
IRP methodology. This recommendation supported fdaho
Power's request in that case.
O. Did the Commission accept your recommendation?
A. No, the Commission did not. The Commission
stated the following in Order No. 32697:
We find that a 21-year contract length, alongwith other factors, has been beneficial in
encouraging PURPA development in Idaho. Wecontinue to believe that 20-year contractsbetter coincide with the useful life of the
renewable/cogeneration resources. While itj-s not this Commission's responsibilit.y to
ensure a contract length that alIows a QF toobt,ain f inancing, we f ind t.hat reducing
maximum contract length to five years wouldunduly hinder PURPA development. That is notthe Commission's objective. We believe that,by utilizing other t.ooIs t.o ensure anaccurate and up-to-date avoided cost
valuat j-on, we can continue to encourage thetypes of projects that were envisioned by
PURPA while maintaining the transparency forratepayers as PURPA requires. Therefore, wefind that a maximum conLract length of 20years is appropriate. The parties to a powerpurchase agreement are free to negotiate ashorter contract if that. would be mostsuitable for the project. As in the past,this Commission will consider contracts of
more than 20 years on a case-by-case basis.
O. The passage from Order No. 32697 you have quoted
above reflects the Commission's position less than two and
a half years ago. Why do you believe the Commj-ssion
should consj-der a different position today?
A. In the short two and a half years since the
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Order was issued, fdaho Power has signed agreements for
461- MW of new solar generation, l and, ds stated in its
Petit,ion, has received pricing requests for 885 MW of
additional solar generation. In response to Staff
production requests, Idaho Power states that it has
received additional requests for solar contracts of
approximately l-20 MW since the filing of this case on
January 30, 20L5. PacifiCorp has received pricing
requests for 275.5 MW of new solar generation according to
its Petition. Contrary to what was contemplated in the
Order, it would not appear that PURPA development needs
further encouragement at this time.
Order No. 32697 suggested that other tools
should be used to ensure accurate and up to date avoided
cost rates, but I believe there are now few other tools
available. Avoided cost rates can be calculated
accurately at the beginning of a contract term, buL no
matter how accurate they may be to start, they are bound
to become inaccurate over a 21-year period for a long term
contract..
a. Is the significant. increase in the cumufative
amount of PURPA power a recent phenomenon?
' The Commission was recently informed by Idaho Power thatfour solar contracts representing l-41 MW have beenterminated for failure to post security.
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A. Yes, as shown in Idaho Power's Exhibit No. 1-,
the total amount of PURPA power began its significant
increase from 2l-6 MW in 2008, to an estimate of 21-87 MW in
2018.2 From lg82 to about 2007, Idaho Power had less than
2OO MW of PURPA generation, primarlly hydro. For
approximately the first 25 years, the average size of
PURPA projects was only about 2.5 MW.
O. Has the Commj-ssion ever before limited contracts
to five years or less?
A. Yes, it has. The Commissj-on's policy with
regard to contract length has evolved over the years.
From 1980 when PURPA was first implemented in Idaho,
through 1-987, utilities were obligated to offer QFs up to
35-year contracts. The reason for the 35-year maximum
contract length was that 35 years was the amortization
period allowed for slmj-Iar utility-owned facilities. A
contracL length that matched the project's amortization
schedule made financing easier, and in effect, helped
encourage QF development.
In 1,987 (See Case No. U-L500-170, Order No.
21530) the Commission shortened the standard contract
' Note that the total estimate for 2ot! includes 885 ofproposed contracts. In addition, it j-ncludes 451 MII'I of ,signed contracts. The Commission was recently notifiedthat 141 MW of signed contracts have defaulted, and thecontracts have been terminated.
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length to 20 years reasoning that risk and uncertainty
j-nherent in long-range forecasting increases dramatically
with time and that a shorter contract term would reduce
that risk. The Commission ruled that contracts longer
than 20 years would be available to QFs only upon a
persuasive showing of need.
Nine years 1ater, in 1996, the Commj-ssion again
reexamj.ned the issue of contract length. In Order No.
2557 6 in Case No. fPC-E-95-9, the Commissj-on further
shortened the maxj-mum required contract length from 20
years to five years for projects 1 MW and larger. In
L997, the Commission extended the five-year contract
length limitation established for large QFs to smaller
than l- MW QFs as weII. (See Case No. IPC-E-97-9, Order
No. 27]-t1,)
In 2002, t,he Commission increased maximum
contract length from 5 years back to 20 years. The
Commission explained that when it earlier had reduced
maxj-mum contract length to five years, there was an
expectation of widespread deregulati-on, more competitive
markets, and greater reliance on short-Lerm market
purchases. However, by 2002, the Commission recognized
that each of Idaho's regulated electric utilities were
constructing or had recently constructed long-term new
generation resources. In restoring 20 years as the
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maximum contract length, the Commission reasoned that a
longer contract better coincides with the planned resource
life of renewable or cogeneration resources being offered,
better reflects the amortization period of generation
projects constructed by the utilities themselves and will
coincidentally provide a revenue stream that will
facj-litate t,he f inancing of QF projects. (See Order No.
29029)
O. During the approximately five and a half year
period when contract length was limited to five years
(September, 1,996 through May, 2002) , weren't very few
PURPA contracts signed?
A. Yes, there was only one PURPA contract signed in
Idaho during this time frame. However, at t,he time, the
eligibility threshold for published rates was also limited
to facilities one megawatt or smal1er. In addition,
published rates were also quite 1ow at this tJ-me,
primarily due to 1ow natural gas prices. Furthermore,
most PURPA hydro and cogeneration projects had already
been developed, while wind, solar and biogas technology
had yet to fu11y develop. The combination of all of these
factors, not shortened contract. length alone, caused very
few PURPA projects to be developed in Idaho during t.his
time period.
O. But won't a five-year limit on maximum contract
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length, if approved, 1j-mit the ability of projects to
obtaj-n financing, thus making extensive project
development unlikely?
A. Yes, I agree that development would 1ikeIy slow
considerably, at least under PURPA. However, facilities
could stil1 be developed under other mechanisms. For
example, if a ut,ility ident,ified a need in its IRP and if
certain renewables or cogeneration possessed the
characteristics and costs making it part of a preferred
portfolio, then the ut,ility could acquire renewables or
cogeneration with long-term contracts in response to
utility requests for proposal. This was the mechanism
employed by Idaho Power in signing power purchase
agreements (PPAs) with the Neal Hot Springs and Raft. River
geothermal projects (35 MW), and the Elkhorn wind
project(101- MW) . Similarly, Avista secured a PPA for the
Palouse wind project in the same way. Fina11y, PacifiCorp
has ej-ther signed multiple PPAs or acquired ownership of
wind projects in the same manner.
QFs could also seII their output to other
utilities outside of Idaho, just as some out of state
projects currently seII their output to Idaho utilities.
In addj-tion, projects could be developed in Idaho and seII
their out.put to out of state buyers, not as QFs under
PURPA, but as Exempt Wholesale Generators. At least one
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large wind project in eastern Idaho se11s its output to
Southern California Edison i-n this fashion. In fact, this
is a very common mechanism for project development
throughout other parts of the country.
Alternatively, projects could also sign PURPA
contracts and replace them every five years (or whatever
maximum contract. length the Commission decides) as long as
PURPA remains in effect.
O. Do you believe that the Commissj-on should
shoulder some responsi-bility for ensuring contract lengths
are long enough to enable QFs to obtain financing?
A. No, not necessarily. Where the Commission
desires to boost development of PURPA projecLs, long-term
contracts may accomplish that goa1. However, currently,
Idaho util-ities, particularly Idaho Power, are being
inundated with more projects than they need or can
accommodate. In Order No. 32697, the Commission stated
that it j-s not the Commission's responsibility to ensure
contracts are long enough to enable projects to obtain
financing. Because the Commission must also regulate the
reasonableness of customer rates and the reliability of
power, it is ultimately a matter of policy-how the
Commission wishes to weigh its various consj-derations.
A. Is a 21-year maximum contract length
inconsistent with PURPA's objectives?
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A. Yes, it can be. One of the Commj-sslon's primary
duties under PURPA is to set avoided cost rates that are
just and reasonable to customers, in the public interest,
and not discriminatory to QFs. Such rates must not exceed
incremental costs to the utility. The concern arises when
contracts extend for many years and the forecast of
avoided cost becomes inaccurate. Long-term contracts
based on forecasted rates create greater risks for
customers because the rates in the later years are not
reflective of avoided cosLs.
O. Are there any specific requirements under PURPA
regarding contract length?
A. No, FERC's regulations implementing PURPA are
silent on contract length. Furthermore, I am not aware of
any FERC case or court decision involvj-ng a requirement
for a minimum contract length.
However, FERC rules do appear to contemplate
less t.han 20 year contracts. Sect.ion 292.302 of the FERC
rules implementing PURPA, requires utilities to make
available information from which avoided costs may be
derived. For energy, util-ities are required to estimate
the energy component of avoided costs by year for the
current. year and each of the next five years. For
capacity, the utility must make available its plan for the
addition of capacity by amount and type, for purchases of
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firm energy and capacity, and for capacity retirements for
each year during the succeeding 10 years. Thus, these
component forecasts are much less than the 2O-year
contract.
In Idaho, utilities do not actually submit such
information t.o the Commission because FERC rules permit
states to require different information for deriving
avoided costs. Nonetheless, I think the mere mention of
five year estimates for energy and 10 years for capacity
suggests 20 year maximum contract lengths are noL
necessarily expected.
a. Are there other reasons why you believe that
maximum contract lengt.h should be shortened to five years?
A. Yes, there are. When the surrogate avoided
resource (Sen; was changed from a coal--fired resource to a
gas-fired resource in 1995, fuel became a much larger
portion of the avoided cost rate. By comparison, fuel is
a far more substantial portion of costs for a gas-fired
resource Lhan for a coal-fired resource. In fact, for the
gas-fired combined cycle combustion turbine (CCCT) now
used as the SAR, fuel represents approxj-mat.eIy two thirds
of the project costs. The fuel component of costs must be
estimated based on 20-year forecasts. As history has
demonstrated, it can be extremely difficult to accurately
forecast gas prices just. a few years into the future, 1et
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alone 20 years int.o the future. Similarly, under the fRP
methodology, much of the cost upon which PURPA rates are
based is driven by fuel prices. Gas-fired generation is
on the margin much of the hours of the year; consequently,
electric market prices are frequently closely tied to
nat.ural gas prices. A five year contract alIows contract
rates to be adjust.ed regularly to more accurately reflect
current fuel prices.
Moreover, a fixed price contract is more risky
than one in which prices are adjusted frequently. A long-
term fixed price could possibly be accurate just once
during its Lerm - at the beginning of the contract when
the rates are first established. The shorter the term of
the contract, Ehe more frequently prices can be adjusted
to ensure they accurately represent the true value of the
power. A shorter term contract helps t.o minimize risk to
ratepayers.
O. Some people have argued over the years that
PURPA projects, because the prices are established at the
start of the contract term and are fixed for the 20 years
of the contract, present 1itt1e or no fuel-price risk
compared to gas-fired generation acquired by utilities.
Do you agree?
A. No, I do not. Although there may be no price
uncertainty associated with long-term PURPA contracts,
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that is not the same as having no price risk. Prj-ces
established at the start of a long-term contract could
prove to be too high or too 1ow compared to other
alternatives or to market. prices in effect throughout t.he
term of the contract. A long-term contract locks in those
prices, regardless of what happens with market prices.
Because 100 percent of PURPA costs are passed on to
customers through PCAs, ratepayers are fu11y exposed to
the risk that PURPA rates prove to be too high.
Fuel costs associated with utility-owned
resources are also passed on to customers, partly through
base rates and partly through PCAs. However, fuel costs
are tracked annually and rates are adjusted accordingly.
Consequently, while customers are exposed to fuel price
risk for both PURPA and utility-owned resources, the
annual adjustment of rates for utility-owned resources
exposes customers to less risk for utility-owned resources
than for PURPA resources.
O. You stated earlier that ratepayers bear 100
percent of the risk when prices in PURPA contracts deviate
from actual values of the power over the life of the
contract. Why shouldn't ratepayers bear L00 percent of
the risk? Don't they bear 100 percent of the risk for
utility-owned resources ?
A. Ratepayers do bear nearly all of the risk of
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ut,ility-owned resources, except for relatively sma11
portions that may be borne by the utilities through cost
sharing mechanisms built into PCAs. However, because of
the annual power cost adjustment mechanisms, the risk for
utility-owned resources is 1ess. In other words, the
annual adjustment allows costs to be bracketed more
accurately.
PURPA resources, on the other hand, receive
revenue at fixed rates over long contract terms. I can
t,hink of few investments made by private investors in
which the rates are fixed and the entire revenue is
guaranteed for 20 year periods. Prj-vate businesses must
almost always make their own assessment of the risks and
rewards for new long term investments. I don't think it
should be much different when private businesses invest j-n
PURPA projects.
O. Do you agree that a long-term PURPA contract
provides long-term price protection, or a "hedge" against
high prices that can benefit ratepayers?
A. It is certainly possible that this could occur,
but it is also possible t.hat long-term price cert.ainty
could lock in high prices to the detriment of ratepayers.
As I stated, price certainty and price protection are not
necessarily the same thing.
O. Do you support fdaho Power's request to limit
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contract length under the IRP methodology to two years or
PacifiCorp's request to limit it to three years?
A. Although I agree with all three ut.ilities'
rationale for two or three year maximum contract lengths,
I think it. could potentially be so short t.hat QFs who did
sign contracts would nearly be in perpetual negotiation to
renew contracts. For some QFs, the negot.iation process
can take months or even more than a year. If many QFs
signed short two or three year contracts, it could be
administrat,ively difficult for both the utilities and the
Commission to review, approve, and manage these contracts.
Therefore, for practical reasons, f think a five year
maxj-mum contract length would be more reasonable.
Moreover, the risk associated with 20-year contract is
greatly reduced when using a contract of five years.
O. Do you support Avista's request to limit
contract length under the IRP methodology, similar to
Idaho Power, but alIow Avista the option to sj-gn contracts
for more than five years in length if a very favorable
opportunity arises? (Reference Kalich, Di at p.3, lines
2-4) .
A. For the same reasons just. stated for Idaho Power
and PacifiCorp, I think a maximum contract length of five
years is more reasonable and manageable for all three
utilities. With regard to Avista's requesL to be able to
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sign contracts for a period of longer than five years in
certaj-n c j-rcumstances, I believe that option has always
existed. I am not opposed to that option continuing to be
avaj-labIe for all three utilities, provided that contracts
longer than five years can be just.ified, will benefit
ratepayers, and are only used in very rare circumstances.
O. What contract length have QFs historically
chosen, both under the SAR and the IRP methods?
A. The vast. majority of QFs in the past have chosen
the maximum contract length available at the time, whet,her
they were SAR or IRP contracts. Some QFs have chosen
shorter contract lengths, generally less than five years/
in most cases because they did not want to be locked into
certain rates for long periods of time. In some cases,
QFs had some expectatj-on that rates would increase in the
future, but wanted to be able to be paid for generation in
the meantime until a longer term contract could be signed
at more attractive rates.
O. Do you know what. the maximum contract length is
for PURPA contracts in other states?
A. I am not familiar with all other states in the
U.S. in which there is significant PURPA activity, but I
do know that maxj-mum contract length is currently 20 years
in Oregon, Utah, and Wyoming. It j-s 25 years in Montana,
but only five years in Washington. In areas where non-
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utility generators have ready access to wholesale power
markets such as P,fM, ISO New England, New York ISO,
California ISO, Southwest Power Pool and ERCOT, there is
no mandatory purchase obligation under PURPA, thus, flo
maximum contract length.
O. Do you believe there may be other options
besides reducing contract lengths that could also address
the problem?
A. The Commission, in Order No. 32697 suggested
that it believed other tools, besides shortened contract
lengths, could be utilized to ensure an accurat.e and up to
date avoided cost valuation. However, the Commission
stopped short of suggesting what those tools should be.
Trying to determine accurate avoided cost rates from the
beginning of the contract is, obviously, a first step.
Although I believe avoided costs are reasonably being
computed t,oday under the IRP method, I also believe that
there may be additional factors that are currently not
being considered. For example, solar projects are
currently eligible for tax credj-ts valued at up to 30
percent of the project cost. Presumably, the value of
these credits is being realized by the owners or
financj-ers of the projects, but is not being passed on to
the utility or j-ts ratepayers. If a utilit.y acquired a
comparable soLar project or its output through a
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competitive solicitation, I would assume the value of any
tax incentives would be reflected in the purchase price
and therefore passed on indirectly to ratepayers.
CurrenLly, tax j-ncentives are not accounted for in the IRP
methodology, yet they provide tremendous benefit to QFs.
There could be other potential changes to the
way in which avoided cost rates are calculated, but none
would adequately address the real problem-rates becoming
inaccurate over long contract lengths.
a. Do you believe a periodic rate adjustment
mechanism could work, while maintaining QFs' option to
choose 20-year contracts?
A. In theory, periodically adjusting rates
throughout the term of the contract, say at two to five
year j-ntervals, could help to ensure that avoided cost
rates in the contract remain accurate and reflect the
proper value compared to the market or other alternatives.
Similarly, indexing prJ-ces in the contract based on
electric market indexes or fuel prices could accomplish
the same thing.
a. Do you believe QFs would find periodic rate
adj ustments acceptable?
A. No, I do not. I expect QFs would vj-ew
adjustable rates, either through reopeners or lndexing, to
be nearly comparable to short term contracts. Because
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prices are the single most important element j-n a
contract, periodic adjustment of those prices could be
functionally equivalent to signing a new contract to QF
owners and financiers.
O. Do PURPA or FERC rul-es al1ow periodic rate
adj ustment,s?
A. FERC and various courts have made clear that
avoided cost rates contained in a PURPA contract cannot be
modified after the contract has been signed, although
neither the Idaho nor t,he U.S. Supreme Courts have held as
much. However, FERC rules do not specifically address
whether adjustable rate cont,racts are acceptable in
instances in which the contracting parties agree in
advance to an adjustment met,hod and frequency.
Consequently, I am uncertain as to whether FERC would find
adjustment, mechanisms acceptable. Because of this
uncertainty, and because I believe QFs would view periodic
rate adjustments as funct,ionally equivalent to new
contracts, I think shorter contracts are the best approach
to reduce the fj-nancial or price risk of long-term
contracLs.
O. Do you agree that. PURPA projects will always be
paid too much under 20-year contracts?
A. No, not necessarJ-Iy. While it is true that
avoided cost rates have exceeded comparable market prices
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throughout most of the hist,ory of PURPA in ldaho, there
have been times when this was not true. For example,
during the extreme electrj-city price spikes in late
2O0L-2002, market price far exceeded avoided cost rates
for extended periods of time.
Price comparisons at any single snapshot in time
are generally not valid projections over a long period of
time. Contractual avoided cost rates will nearly always
be higher or lower than comparable market prices over the
long-term such as 20 years. What is important is that the
prices are close over the entire course of the contract
term.
Now that a few contracts have reached or are
nearing their 20 or 35-year expiration, a comparison can
perhaps be made. However, j-n my opinion, if avoj-ded cost
rates in any contracts have proven to be accurate over
time, it has been just by chance, not by design.
a. Do you think it is fair for utilities to be
permitted to develop or acquire long-term generation
asseLs, but to only be obligated 1n the case of PURPA
resources to Lwo, three, or five year contracts?
A. Whenever a utility acquires a resource or signs
a long-term PPA for new generation, it must identify the
need in its fRP, evaluate a range of alternatj-ves, and
procure the resource or contract through a competj-tive
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process. Throughout the entire process, the utility's
decisions are subject to intense scrutiny by the
Commission, intervenors, and other interested parties,
including customers. If the utility cannot, first
demonstrate a need and second justify the cost-effective
resource, it does not receive Commission approval to
pursue the project.
As examples of utility acquisitions of non-PURPA
renewable projects, Idaho Power's Neal Hot Springs and
Raft River geothermal PPAs and j-ts Elkhorn Wind PPA were
signed as a result of geothermal and wj-nd resources being
identified as preferred resources in the utility's IRP.
Similarly, Avista's Palouse Wind Project PPA and several
PacifiCorp wind projects and PPAs were identified through
the IRP process and acquired through subsequent
competitive procurement processes.
O. Was the procurement of thermal projects by
utilities, such as Idaho Power's Langley Gulch project,
PacifiCorp's Lakeside II, or Avista's Lancaster PPA any
different than the acquisition process employed for
renewables? Aren't those examples of long-term
commitments that bind ratepayers for very long periods of
t.ime?
A. Just like the renewabl-e projects previously
di-scussed, the utilities' thermal facilities mentioned
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above also had to pass intense scrutiny before the
utilities were permitted to procure them. While it is
true that utilities are permltted to sign long-term
contracts and secure long-term financing, for most
projects there is no guaranteed complete cost recovery at
fixed rates. For example, in the case of Idaho Power's
Langley Gulch project, varj.ous costs of the facility are
included in base rates for recovery over the life of the
pIant. However, fuel costs, which can represent as much
as two thirds of the total cost over the facility's
lifetime, are subject to annual adjustment to the extent
actual- costs vary from what is included in base rates.
Moreover, most of these thermal generating facilities
provide other benefits such as dispatchability, variable
ramp rates, reserves and other ancillary services.
PURPA projects, oD the other hand, are treated
differently. They are currently entitled to long-term
contracts at fixed rates. The utility 1s obligated to
sign contracts at Commission-approved rates, with no
consideration of need, with no competitive procurement
process, and without regard to cost-based pricing.
Recovery of PURPA contract payments by the utility is
through a combinat.ion of base rates and PCAs, but always
at 1-00 percent. There is no adjustment to the avoided
cost rates or to the amount authorized for recovery from
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ratepayers throughout the entire term of the contract.
O. Can PURPA cogeneration projects like Simplot or
Clearwater present additional risks over non-cogeneration
PURPA projects?
A. Perhaps. Cogeneration projects are always
associated with some other industrial process besides
generating electricity. Consequently, they face business
risks independent of their electric production. If the
thermal hosE for a cogeneration facility goes out of
business, then the electric production cannot continue.
Some examples of this have been the Magic West facility in
Glenns Ferry and the Yellowstone Power project at Emmett.
O. Do you believe PURPA is an effective mechanism
for utilities to acquire new generation?
A. No, I do not. I believe PURPA was intended to
permit relatively sma11, non-utility-owned projects to be
developed and to compete on an equal footing with utility-
owned facilities. I do not believe PURPA was ever
intended to serve as the primary, or even a major,
mechanism for utj-Iity acquisition of new resources.
Instead, at least for Idaho Power and perhaps PacifiCorp,
PURPA resources have become major resources, forced upon
them with no planning whatsoever. PURPA projects entirely
circumvent the plannj-ng process and sometj-mes cause the
utility to plan around them rather than planning for them.
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This creates a very awkward and inefficient planning
process and can lead to a poorly conceived generation
fleet that is not in the best interests of ratepayers.
Therefore, I do not support long-term contracts to
encourage PURPA at a time when util-ities would not
otherwise be making long-term commitments for non-PURPA
generatj-on resources .
O. Each of the utilities' petitions in this case
have asked to reduce the maximum length of only IRP-based
conLracts; however, SAR-based contracts continue to be
eligible for 20-year contracts. Do you believe 20-year
maximum contract lengths should continue to be available
to SAR-based contracts?
A. Yes, I do. Twenty
continue to be available for
smaller than 100 kW, and for
smaller than 10 aMW.
year contracts should
wind and solar projects
all other project t.ypes
O. If maximum contract lengths are reduced to less
than 20 years in this case for lRP-based contracLs, are
you concerned about the difference j-n contract length
between SAR-based and IRP-based contracts?
A. No, f am not. Although there would be a
difference between maximum contract length for IRP and
SAR-based contracts, I believe such a difference is
reasonable. In the past, there have been insLances in
cAsE NOS. rPC-E-15-01/AVU-E-15-01- STERLTNG, R. (Di) 25PAC-E-15-03 STAFF
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which contract rates and/or terms were much more favorable
for SAR-based than for IRP-based contracts, and it has led
to QF developers strongly preferring one contract type
over the other. One recent example was the disparity in
rates (either real or perceived) between IRP and SAR
rates, which led to disaggregation of large wind farms
into smaller 10 MW projects.
In this case, most new PURPA projects are 1ike1y
to be solar, and the size limit or eligibility cap for
SAR-based solar contracts is 100 kW. Because this cap j-s
l-00 kW, I believe it is unlikely a QF would be
disaggregated into such sma11 pieces in order to qualify
for SAR-based rates, or more importantly, for 2O-year
contracts. The same would 1ikeIy be true for wind
proj ects.
In addition, SAR-based projects do not represent
a significant portion of the cumulatj-ve amount of PURPA
generatj-on. For example, wind and solar projects (both
under contract and proposed) account for more than L973 MW
of Idaho Power's PURPA projects according to Idaho Power
Exhibit No. 1. Thus, the impact of SAR-based projects is
very smal-l in comparison to the magnitude of IRP-based
proj ects .
O. Does your proposal to maj-ntain 20-year contracts
for new SAR-based projects also apply to SAR-based
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contracts that will be expiring and that desire new
contracts?
A. Yes, it does.
O. Please discuss the number and timing of expiring
SAR-based contracts.
A. In the comj-ng years, many existing PURPA
contracts will expire and will be seeking replacement
contracts. Exhibit No. 101 depj-cts graphically t,he t.iming
and number (but not t.he amount of generation) of QF
contracts that will be expiring. Each line on the graph
represents a different contract. In the comj-ng 10 years,
94 contracts will expire and could choose to be renewed.
O. Why should SAR-based contracts be permitted
longer contracts than IRP-based contracts?
A. Neither SAR-based nor IRP-based rates are Iike1y
to remaj-n accurate over a 2)-year period. On a per kW
basis, the risk for SAR-based contracts is exactly the
same as for IRP based contracts. However, SAR-based
contracts, because the project sizes are individually and
collectively sma11, present much less risk if contract
rates prove to be too high or too Iow compared to the
actual value of the power.
O. Should SAR-based replacement contracts be
permitted 20-year terms?
A. Yes, I recommend that all SAR-based cont,racts be
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eligible for 20-year contracts, regardless of whether they
are for new projects or for replacement contracts. SAR-
based projects that are renewing contract,s will receive
the then current energy rates and capacity rates. Even
though projects seeking replacement contracts presumably
have already been financed and ret.ired their debt, for
consistency sake I think it is reasonable that all SAR-
based contracts fo1Iow the same rules.
Contracts that were initially SAR-based, but at
the time of contract replacement exceed the si-ze threshold
for SAR-based rates, should be treated as new IRP-based
contracts but eligible for capacity payments throughout
t.he entire contract term.
a. Please summarize your recommendations.
A. I recommend that the maximum contract length for
standard IRP-based contracts be five years for Idaho
Power, PacifiCorp, and Avista. I also recommend that the
maximum conLract length for SAR-based contracts remain at
20 years, both for new and for replacement contracts.
A. Does this conclude your direct testimony in this
proceeding?
A. Yes, it does.
CASE NOS. rPC-E-15-01/AW-E-15-01 STERLTNG, R. (Di) 28
PAC-E-15-03 STAFF
4/23/Ls
Expiration of PURPA Contracts Over Time
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ExhibitNo. l0l
Case No. IPC-E-15-01
AW-E-15-01
PAC-E-15-03
R. Sterling, Staff
4123lt5
CBRTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 23RO DAY oF APRIL 2015,
SERVED THE FOREGOING DIRECT TESTIMONY OF RICK STERLING, N
CASE NOS. IPC-E-I5-01/PAC-E-15.03/AVU-E-15-01, BY E-MAILING A COPY
THEREOF, POSTAGE PREPAID, TO THE FOLLOWING:
DONOVAN E WALKER PETER J RICHARDSON
REGULATORY DOCKETS GREGORY M ADAMS
IDAHO POWER COMPANY RICHARDSON ADAMS PLLC
PO BOX 70 PO BOX 7218
BOISE ID 83707-OO7O BOISE ID 83702
E-mail: [e-mail] E-mail: [e-mail]
[e-mail] [e-mail]
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6070 HILL ROAD ID CONSERVATION LEAGUE
BOISE ID 83703 710 N 6TH STREET
E-mail: [e-mail] BOISE ID 83702
E-mail: [e-mail]
DEAN J MILLER LEIF ELGETHUN
MoDEVITT & MILLER LLP INTERMOI-INTAIN ENERGY PARTNERS
420 W BANNOCK ST LLC
BOrSE rD 83702 PO BOX 7354
E-mail: [e-mail] BOISE ID 83707
E-mail: [e-mail]
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PO BOX I73I E.MAIL ONLY:
BOISE ID 83701 [e-mail]
E-mail: [e-mail]
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ID REG AFFAIRS MANAGER YVONNE R HOGLE
ROCKY MOLINTAIN POWER ROCKY MOLINTAIN POWER
201 S MATN ST STE 23OO 201 S MAIN ST STE 24OO
SALT LAKE CITY UT 841I I SALT LAKE CITY UT 84I I1
E-mail: [e-mail] E-mail: [e-mail]
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DATA REQUEST RESPONSE CENTER C TOM ARKOOSH
E-MAIL ONLY: ARKOOSH LAW [e-mail] PO BOX 2900
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ARKOOSH LAW OFFICES RACINE OLSON NYE BUDGE
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29814 LAKE ROAD WILLIAMS BRADBURY PC
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E-mail: [e-mail] BOISE ID 83702
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SANGER LAW PC AVISTA CORPORATION
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AVISTA CORPORATION SIERRA CLUB
I4I I E MISSION AVE 85 SECOND ST 2ND FLOORMSC-23 SAN FRANCISCO CA 94105
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SR ASSIST GEN COUNSEL PAMELA S HOWLAND
MICRON TECHNOLOGY INC HOLLAND & HART LLP
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AMALGAMATED SUGAR CO
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CLEARWATER PAPER CORPORATION
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SR VP NORTH AMERICA DEVL
CAMCO CLEAN ENERGY
9360 STATION ST STE 375
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