20150130Application and Attachment.pdf

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An TDACORP Comoanv
DONOVAN E. WALKER
Lead Counsel
[e-mail]
January30,2015
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Enclosures
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VIA HAND DELIVERY
Jean D. Jewel!, Secretary
ldaho Public Utilities Commission
472 West Washington Street
Boise, ldaho 83702
Re: Case No. IPC-E-15-01
Modify Terms and Conditions of Prospective PURPA Energy Sales
Agreements - ldaho Power Company's Petition and Testimony
Dear Ms. Jewell:
Enclosed for filing in the above matter please find an original and seven (7)
copies of ldaho Power Company's Petition.
Also enclosed for filing are an original and eight (8) copies each of the Direct
Testimony of Lisa A. Grow and Randy Allphin. One copy of each of the aforementioned
testimonies has been designated as the "Reporter's Copy." !n addition, a disk
containing Word versions of Ms. Grow's and Mr. Allphin's testimonies is enclosed for
the Reporter.
lf you have any questions about the enclosed documents, please do not hesitate
to contact me.
Very truly yours,
/'-) ,.- / ../2LZcuU
-Donoran E. Walker
1221 W. ldaho St. (83702)
PO. Box 70
Boise, lD 83707
DONOVAN E. WALKER (lSB No. 5921)
ldaho Power Company
1221West ldaho Street (83702)
P.O. Box 70
Boise, ldaho 83707
Telephone: [phone]
Facsimile: [phone]
dwalker@ idahopower. com
Attorney for ldaho Power Company
IN THE MATTER OF IDAHO POWER
COMPANY'S PETITION TO MODIFY
TERMS AND CONDITIONS OF
PROSPECTIVE PURPA ENERGY SALES
AGREEMENTS.
t,. ?n5'Lu
CASE NO. |PC-E-15-01
IDAHO POWER COMPANY'S
PETITION TO MODIFY TERMS AND
CONDITIONS OF PROSPECTIVE
PURPA ENERGY SALES
AGREEMENTS
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
I. INTRODUCTION AND SUMMARY
ldaho Power Company ("ldaho Powe/' or "Compoly"), pursuant to RP 56,
hereby respectfully petitions the ldaho Public Utilities Commission ("Commission") to
issue an order modifying the terms and conditions by which ldaho Power must purchase
energy generated by Qualifying Facilities ("QF") pursuant to SS 201 and 210 of the
Public Utility Regulatory Policies Act of 1978 ('PURPA") and various Commission
orders. ldaho Power's request to modify terms and conditions for prospective PURPA
IDAHO POWER COMPANY'S PETITION TO MODIFY TERMS AND
CONDITIONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS - 1
energy sales agreements is limited to transactions with proposed QF projects that
exceed the published rate eligibility cap.1
Specifically, the Company believes the continued creation ol ZO-year term
contracts places undue risk on customers at a time when ldaho Power has sufficient
resources to meet customer demands. The Company's required lntegrated Resource
Plan ("lRP") process is filed and updated every two years. Non-PURPA purchase and.
sales transactions are limited to less than two years pursuant to the Company's
approved risk management policy. Avoided cost rates are updated at least every year.
Therefore, ldaho Power requests that the Commission issue an order directing that the
maximum required term for prospective ldaho Power PURPA energy sales agreements
be reduced from 20 years to two years.
ldaho Power currently has a total of 1,302 megawatts ("MW") of PURPA QF
projects under contract. Allphin, Ex. 2. Of that total, 781 MW of capacity from these
projects are on-line and operational today. ld. Idaho Power has 577 MW of PURPA
wind capacity currently operating on its system, with an additional 50 MW under
contract to be on-line in 2016. /d The Company has 461 MW of PURPA solar capacity
under contract to be on-line in 2016, and an additiona! 885 MW of PURPA solar
capacity in the queue actively seeking PURPA energy sales agreements to be on-line in
2016. Allphin, Ex. 1;Ex.2. ln total, ldaho Powertoday has 2,187 MW of PURPA
generation operating, under contract, or currently requesting long-term, fixed-price
energy sales agreements to be on-line in 2016. ld.
1 The published rate eligibility cap is 100 kilowatts for wind and solar QFs and 10 average
megawatts for all other QF generation types.
IDAHO POWER COMPANY'S PETITION TO MODIFY TERMS AND
CONDITIONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS - 2
ldaho Power's customer obligation for the current 781 MW of constructed and
operating QF capacity is approximately $2.6 billion over the life of the respective
agreements. Allphin, Ex. 4. The additional 461 MW of approved solar QF contracts
represents an additional financial obligation to be borne by customers of approximately
$1.6 billion. ld. The addition of the 885 MW of proposed solar QF projects would
represent yet another long-term financial obligation to customers of approximately $2.1
billion. ld. The addition of the recently proposed PURPA solar generation would take
ldaho Power's and its customers' obligations under PURPA from the existing $2.6 billion
to $6.4 billion of contractually obligated energy payments, all of which must be borne by
ldaho Power customers. /d.
The Commission in its recent approval of the last 11 PURPA solar energy sales
agreements has questioned the continued acquisition of such large amounts of PURPA
generation when there is not an associated need for that generation on ldaho Power's
system.2 The Commission stated in those orders, "Unfortunately, PURPA does not
address and FERC regulation does not adequately provide for consideration of whether
the utility being forced to purchase QF power is actually in need of such energy." See
fn. 2. ldaho Power currently has generation capacity sufficient to reliably serve
customers'peak consumption, or demand, through the year 2021, and has sufficient
resources to meet customers' energy consumption (monthly average) beyond the 20-
year IRP planning horizon, past 2033. Order No. 33159;2013 lRP, p. 60. Additionally,
the Company's 2013lRP has identified the Boardman to Hemingway transmission line
as the primary resource in the near-term action plan. The Boardman to Hemingway
' Order Nos. 33198, pp. 5-7; 33199, pp. 5-7; 33200, pp. 5-7; 33201, pp. 56; 33202, pp. 5€;
33204, pp.6-7;33205, pp.6-7;33206, pp.7-8; 33207, pp.6-8;33208, pp.6-8;33209, pp.6-8.
IDAHO POWER COMPANY'S PETITION TO MODIFY TERMS AND
CONDITIONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS - 3
transmission line would serve additiona! growth for years beyond the next identified
need in 2021 without adding any new generation plants.
The Commission expressed concern about passing those substantial costs for
unneeded resources on to ldaho Power customers. The Commission concluded each
of the orders, footnoted above, with expression of its concern about ldaho Power's
ability to continue to take such large amounts of intermittent generation stating, "While
we are pleased with the progression of the IRP methodology, avoided cost rates are not
the only terms to a PURPA contract. The utilities are in the best position to inform the
Commission if review of additional PURPA contract terms and conditions is warranted."
See fn. 2.
The requested modification to terms and conditions of required PURPA energy
purchases is necessary to prevent harm to ldaho Power's customers that may result
from entering into additional long-term, fixed-rate purchase agreements/obligations
when there is no need for such generation. ldaho Power should not be obligated to
enter into prospective long-term contracts for the large amount of proposed QF solar
generation, nor should ldaho Power customers be obligated to pay for such long-term
purchases when there is no need for such power production.
Several issues related to the Commission's implementation of PURPA in the
state of ldaho could warrant additional examination and possible revision. These items
could include: (1) further modification to the existing avoided cost pricing
methodologies to more appropriately reflect need and resource sufficiency in the price;
(2) implementation of new avoided cost pricing methodologies which move to a market-
based or competitively bid-based avoided cost mechanism, such as that utilized in
IDAHO POWER COMPANY'S PETITION TO MODIFY TERMS AND
CONDITIONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS - 4
Washington; (3) exemption from PURPA under S 210, part M; (4) Commission pursuit of
a waiver from the requirements of S 210, subpart C, for Idaho Power pursuant to 18
C.F.R. S 292.402; (5) refinement of the Commission's 90%/110o/o definition of firmness
to require firm scheduled deliveries for entitlement to rates established at the time of
contracting or legally enforceable obligation, as opposed to rates determined at the time
of delivery, similar to the implementation in Texas; (6) further refinement of the eligibility
for rates established at the time of contracting or legally enforceable obligation by
requiring QFs to be within 90 days of delivering power before the utility is obligated to
the price, again similar to the implementation in Texas; (7) modification of contractual
term limitations; and (8) establishment of caps, or MW targets, upon the amount of new
or repowered projects a utility is required to procure over a given period of time, similar
to those in place in California. While the Company believes each of these issues may
warrant further examination, at this time, ldaho Power's specific request with this
Petition is that the Commission modify the terms and conditions of prospective
purchases from PURPA QFs by reducing the current 2O-year contract term for ldaho
Power energy sales agreements to a maximum of two years, and direct any other relief
it deems appropriate and in the public interest.
This Petition is supported by the accompanying testimony and exhibits of Lisa A.
Grow and Randy Allphin as well as the previously sworn, admitted, and cross-examined
Direct Testimony of William H. Hieronymus from Case No. GNR-E-11-03, attached
hereto as Attachment 1, and is based on the following:
IDAHO POWER COMPANY'S PETITION TO MODIFY TERMS AND
CONDITIONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS - 5
II. BACKGROUND
A. PURPA.
Sections 201 and 210 of PURPA require electric utilities to offer to purchase
electric energy from qualifying cogeneration and small power production facilities. 16
USC S 824a-3(a). PURPA further specifies that the purchase rates set by state
commissions for electric utility purchases of energy generated by QFs may not exceed
the incremental cost to the electric utility of alternative electric energy. 16 USC $ 824a-
3(b) PURPA defines incremental cost as the cost to the electric utility of the electric
energy which, but for the purchase from such QFs, such utility would generate or
purchase from another source. 16 USC S 82aa-3(d). PURPA also requires state
commissions to set the rates for purchases of power from QFs at levels that are just and
reasonable to the utility's customers and in the public interest and that do not
discriminate against QFs, but that are not more than avoided costs. 16 USC $ 824a-
3(bxl) and (2).
Congress enacted PURPA to encourage the development of cogeneration and
small power production facilities, and directed the Federal Energy Regulatory
Commission ("FERC") to promulgate regulations to further this goal. 16 U.S.C. $ 824a-
3(a); FERC v. Mississrppi, 456 U.S. 742,750-51, 102 S.Ct. 2126,72 L.Ed.zd 532
(1982). PURPA also requires that the state regulatory authorities, such as the ldaho
Public Utilities Commission, implement the FERC regulations. 16 U.S.C. $ 824a-3(Q.
ln FERC v. Mississippi, the U.S. Supreme Court found that a state may comply with its
obligation to implement PURPA and FERC regulations "by issuing regulations, by
resolving disputes on a case-by-case basis, or by taking any other action reasonably
IDAHO POWER COMPANY'S PETITION TO MODIFY TERMS AND
CONDITIONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS - 6
designed to give effect to FERC's rules." 456 U.S. at751,102 S.Ct. 2126,72 L.Ed.2d
532. FERC has further stated that states may fulfill the requirement to implement its
rules by "either 1) through the enactment of laws or regulations at the State level; 2) bV
application on a case-by-case basis by the State regulatory authority, or nonregulated
utility, of the rules adopted by the Commission [FERC]; or 3) by any other action
reasonably designed to implement the Commission's [FERC'st rules." Policy Statement
Regarding the Commission's Enforcement Role Under Secfion 210 of the Public Utility
Regulatory Policies Act of 1978,23 FERC P 61304, 61644, 1983 WL 39627 (May 31,
1 e83).
The Commission has implemented the provisions of $ 292.304 (Rates for
Purchases) with regard to ldaho Power by making available the two pricing options
referred to in $ 292.304(d) at the election of the QF. First, a QF may select to sell "as
available" pursuant to ldaho Power's Tariff Schedule 86, Cogeneration and Small Power
Production Non-Firm Energy. IPUC No.29, Tariff No. 101, Sheet No.86-1 through
86-7. This pricing option is availabb for QFs selecting to receive rates based upon the
utility's avoided cost at the time of delivery. Second, for QFs that select to have pricing
established for a specified term according to the utility's avoided cost at the time of
contracting, or when the obligation is incurred, the Commission has authorized the use
of two avoided cost pricing methodologies. A surrogate avoided resource ("SAR")
methodology is used for small projects below the published rate eligibility cap, currently
set at 100 kilowatts for wind and solar QFs and 10 average megawatts for all other QFs.
For QFs that are larger than the published rate eligibility cap, an avoided cost
methodology based upon the utility's IRP is used to establish the starting point for
IDAHO POWER COMPANY'S PETITION TO MODIFY TERMS AND
CONDITIONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS - 7
negotiating the avoided cost rate for each specific project. The Commission reviews
each QF power purchase agreement, and Commission approval of each agreement,
including its prices, terms, and conditions is required prior to such agreement being
effective.
B. Gommission's Authoritv to Determine Terms of Gonditions of PURPA
Purchases.
The Commission has changed the authorized maximum term of a required
PURPA purchase several times throughout its implementation of PURPA in the state of
ldaho. The various changes to the maximum contractual term have resulted from the
Commission's evaluation of changing conditions in the energy and utility environment
and its attempts to balance the promotion of the development of QF resources with the
cost and risk borne by ldaho Power and its customers in the transaction. From 1980
when PURPA was first implemented in the state of ldaho through 1987, utilities were
obligated to provide QFs with a 35-year contract. ln 1987, the Commission shortened
the maximum term to 20 years based primarily upon the inherent uncertainty in long-
term forecasting. Order No. 21630. In 1996, the Commission further reduced contract
term to five years for QFs of 1 MW and Iarger, the published rate eligibility cap at that
time. Order No. 26576. ln 1997, the Commission extended the five-year contract term
limitation to include QFs under the 1 MW published rate eligibility cap as well. Then, in
2002, the Commission went back to a 20-year contract term, which has been in place to
the present. Order No. 29029.
The maximum contractual term for a mandatory purchase under PURPA is an
extremely important term and condition of the contract and sale. The price, terms, and
conditions in a mandatory PURPA purchase, when the QF selects rates determined at
IDAHO POWER COMPANY'S PETITION TO MODIFY TERMS AND
CONDITIONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS - 8
the time of contracting/obligation for the duration of the contract, cannot be changed,
adjusted, or effected at all, once approved and effective. FERC's view with regard to
the Commission's inclusion of costs in long-term contracts was discussed in a recent
Idaho Power case. ldaho Wind Partners 1, LLC., Docket No. EL12-74-000, 140 FERC
fl 61.219 (September 20, 2012)(Order Granting Petition for Declaratory Order);
EL12-74-001, 143 FERC 11 61,248 (June 20, 2013) (Order on Rehearing). ln the ldaho
Wind Partners case, FERC insisted that all long-term PURPA contracts containing rates
established at the time of contracting will be assumed to include all costs, even in the
face of direct evidence that certain costs were not included in the avoided cost rates at
the time of contracting. Order on Rehearing, supra. Additionally, FERC's position is
that once avoided cost rates are established in the contract at the time of contracting,
they cannot subsequently be changed. ld. While FERC's position is that the state
commission may not change or revise a PURPA contract during its term because such
action may constitute utilitytype regulation of a QF in violation of 18 C.F.R. S
292.602(cX1), the state commission may review and approve a PURPA contract at the
time it is submitted by the parties for final approval, in furtherance of its state duty to
ensure that the agreement is consistent with the public interest. Crossroads
Cogeneration Corp. v. Orange & Rockland Utilities, lnc., 159 F.3d 129, 138 (3d
Cir.1998)("ln other words, while PURPA allows the appropriate state regulatory agency
to approve a power purchasing agreement, once such an agreement is approved, the
state agency is not permitted to modify the terms of the agreement.").
The Commission has the obligation to ensure that the avoided cost rate and the
purchase of QF generation is just and reasonable to the utility's customers, in the public
IDAHO POWER COMPANY'S PETITION TO MODIFY TERMS AND
CONDITIONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS - 9
interest, and that customers are not harmed by the PURPA QF obligation. lnherent in
that authority is the ability to determine the appropriate term of the purchase, as well as
the other terms and conditions of the purchase and sale. The ldaho Supreme Court
recently upheld the Commission's authority and procedure by which it approves or
disapproves PURPA power sales agreements and determines whether a legally
enforceable obligation exists that would bind the QF, utility, and its customers even in
the absence of a contract. ldaho Power Co., v. ldaho Pub. Util. Comm.,155 ldaho 780,
316 P.3d 1278 ("Grouse CreeK'). Determination of the proper terms and conditions of a
required PURPA energy sales agreement, including the authority to determine the
proper price, the proper contractual term, and the authority to approve or disapprove the
contract itself is soundly, and completely, within the authority and discretion of the
Commission.
C. ldaho Power's Low Carbon Emissions and Renewable Generation.
ldaho Power is a vertically integrated electric utility which began operations in
1916. ldaho Power serves more than 513,000 customers throughout a 24,000 square
mile area in southern ldaho and eastern Oregon. ldaho Power owns and operates 17
hydroelectric generating facilities, primarily on the Snake River, which provide the bulk
of the Company's generating ability. ldaho Power has a nameplate generation capacity
of nearly 3,600 MW. ldaho Power's highest historical peak system load was nearly
3,600 MW, which occurred on July 2,2013. The Company's peak system load for 2014
was approximately 3,184 MW. lts minimum system load for 2014 was approximately
1,073 MW. ldaho Power residential, business, and agricultural customers consistently
pay some of the nation's lowest prices for electricity.
IDAHO POWER COMPANY'S PETITION TO MODIFY TERMS AND
CONDITIONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS - 1O
ldaho Power's five-year average fuel mix consists of over 58 percent renewables
as shown in the chart below.
Idaho Power's
Fuel Mix*
Renewables
Hydroelectric
Natural Gas
Other
Renewables
*Because ldaho Power does not own the Renewable Energy Certificates (REC) associated whh all
of these resourcet we cannot and do not represent tiat electricity produced by this fuel mix is
being delivered to our retail customers. For more information, visit our website.
Idaho Power has always been a low carbon emitting and primarily renewable
energy electric utility. ldaho Power is nearly 100 years old, and its first generation
facility was hydroelectric. ldaho Power believes in a diverse generation portfolio that
also utilizes demand-side management and energy efficiency programs to meet the
needs of its customers. As of December 31 , 2014, ldaho Power had 1,428 MW of
IDAHO POWER COMPANY'S PETITION TO MODIFY TERMS AND
CONDIT]ONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS. 11
renewable energy (PURPA and non-PURPA purchases3; on its system or under
contract, excluding the Company's hydro resources. Allphin, Ex. 2. This renewable
generation consists of: 728 MW of wind, 461 MW of solar, 35 MW of geothermal, and
184 MW of small PURPA hydro and other. The state of ldaho does not have a
renewable portfolio standard ("RPS"), but with only its currently existing resources the
Company would meet an RPS standard ol 20 percent of retail load (megawatt-hour
("MWh")) supplied by renewable energy (MWh). Allphin, Ex. 5. When ldaho Power's
1,709 MW of hydroelectric nameplate capacity is combined with the Company's
acquired renewable capacity, ldaho Power has over 3,100 MW of renewable generation
capacity, which equates to 90 percent of retail load supplied by renewable energy. ld.
lf the Company's PURPA generation, including PURPA solar under contract and
proposed, were considered, ldaho Power would meet an RPS standard of 37 percent of
retail load supplied by renewable generation, which exceeds the RPS requirements of
its neighboring western states, as well as California, as shown in the graph below.a
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3 Non-PURPA purchases of 136 MW include Elkhorn Wind, 101 MW; Raft River Geothermal, 13
MW; and Neal Hot Springs Geothermal ,22 MW.
o This comparison is done to show the magnitude of QF development and Company-owned hydro
compared to various mandatory RPS requirements. Because ldaho Power does not receive the
Renewable Energy Certificates/Credits ("RECs") from most of its QF generation, this generation cannot
be used to meet any potential RPS requirements. ldaho Power cannot represent to customers that they
are receiving renewable energy from the QFs, or from generation, for which it does not receive the RECs,
and is not making any such representation here.
IDAHO POWER COMPANY'S PETIT]ON TO MODIFY TERMS AND
CONDITIONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS - 12
ldaho Power Compared to Regional Renewable Portfolio
Standard (RPs)/Renewable Portfolio Goal(RPG)
100%
3Er*
o!
o 80ft,qt!
o6 zoxG
3o
5 ooru
E
.ct __-
- )UlE
.9
CLcL 40%5]a
; r0%
E
u2MGo
= 1046
G
o
Eo*oa
l. --------
I
77'r
PURPA
uullryPPA
46tMW
Solar
gOY.
PURPA
utllty PPA
il61MW
Solar
885MW
Solar
lPCo llydro
lPCoHydro l'x
$%
24%
..j
TI,RPA.. ...
umqPql.
{01irw "
!Idiri.::,..
PURPA
udlity PPA
,[61MW
Sol*
885MW
Solrr
2014 L077 l0l7 1077 20\7 2020
ldahoPower ldahoPorver ldahoPolver ldahoPorver ldahoPolver CA RPS
Actual tstimated trtinrated Estimated Estirnated
2025 2025 2025 2020
I{V RPS OR RPs UT RPG WA RPI
2015
MT RPs
Idaho Power is one of the lowest carbon emitting utilities in the industry. Based
upon overall 2012 emissions, ldaho Power is ranked among the 36 Iowest, and, for
emission intensity (per MWh), is among the 38 lowest carbon dioxide emitters among
the nation's 100 largest electricity producers. ldaho Power's relative carbon emissions
are set out in the chart below.
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IDAHO POWER COMPANY'S PETITION TO MODIFY TERMS AND
CONDITIONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS - 13
I
2,}v.
Carbon Emissions:
How ldaho Power compares [3ll*r3t*1?1n",,,
ldaho Power is 38th{owest among
fie nation's 1 m largest electricity
prodwe* Source: 2012 data.
US Ercrgy lnfornation Administation.
Idaho
Power
* 172i33'.
* 48 TBERDRoLA
ldaho Power charts its carbon intensity in its annual sustainability reports, as well as
tracking and displaying its progress on its website. ldaho Power established a carbon
emission intensity goal in 2009 to reduce average carbon dioxide emission intensity for
the 2010 to 2013 period by 10 to 15 percent below its 2005 intensity oI 1,194 pounds
per MWh. ln November 2012, ldaho Powe/s Board of Directors approved extending
that goal through 2015. By the end of 2013, ldaho Power had reduced its average
carbon dioxide intensity over the 2010 to 2013 period to 929 pounds per MWh, a 22
percent reduction from 2005 carbon dioxide intensity. Preliminary results for the year
ending 2014 show that the Gompany remains on track with approximately 944 pounds
per MWh, which is a 21 percent reduction from 2005 levels.
IDAHO POWER COMPANY'S PETITION TO MODIFY TERMS AND
CONDITIONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS - 14
Being a predominately hydro-based system, ldaho Power's carbon intensity
varies based upon the hydrologic conditions; that is, good water years help reduce
carbon emissions. However, ldaho Power has taken other steps to reduce emission
intensity. The most recent addition to ldaho Power's generation is the Langley Gulch
natural gas-fired plant, which was originally planned to be a coal plant, generates with
about half of the carbon dioxide intensity of a coal-fired plant, helps with integration of
intermittent renewable energy, and provides an option to further reduce carbon dioxide
emissions and intensity by fuel switching from coal to natural gas. ldaho Power has
also been working to maximize effective utilization of its existing hydroelectric
resources. Recent turbine upgrades have seen efficiency gains of 3 to 5 percent
increases in MW generated with the same amount of water. This also includes cloud
seeding and effective water leasing practices. ldaho Power's current cloud seeding
project includes 36 ground generators and an aircraft, which results in an estimated
193,000 MWh of additiona! hydroelectric generation. Expansion of the cloud seeding
program could produce an estimated additiona! 277,000 MWh of hydroelectric
generation.
Beyond carbon dioxide, ldaho Power has been working to reduce NO, and SOz
emissions from coal-fired plants and has seen a dramatic decrease in those emissions
since 1998 because of enhanced operating efficiencies at the plants, improvements in
pollution control equipment, and increased integration of renewable energy. ln
testimony from Case No. IPC-E-13-16 during 2013, ldaho Power discussed a path for
the eventual retirement of coal resources. As the Company seeks to balance the
impacts of carbon with the economic realities of its customers, it knows that it cannot
IDAHO POWER COMPANY'S PETITION TO MODIFY TERMS AND
COND]TIONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS - 15
immediately terminate operation of coal-fired plants. As the Company continues to
evaluate its coa! plants from an economic standpoint, from the context of 111(d), and
from all relevant considerations, it is mindful that those plants have a finite life. The
Company sees no new coal plants in its future as evidenced in its 2013 IRP. The
Company has planned for a shutdown of its coal-fired operations at the Boardman
power plant in 2020. ldaho Power has also been in discussions with the joint owner of
the Valmy plant regarding the future of that plant and the resource alternatives that
could replace the generation from that plant. Cost is an ongoing consideration. State
public utility commissions and ldaho Power's customers demand that costs and risks be
considered such that future rate increases are mitigated where possible. Idaho Power
and its customers benefit from the current diversity of generation resources, and that
diversity helps mitigate the power supply cost risk borne by customers as the Company
transitions to the new energy landscape.
Many things have changed in the energy landscape over the last decade. The
continuing emergence of carbon legislation, rules, and constraints as well as the
magnitude of contracted renewable energy from PURPA require increased scrutiny.
ldaho Power has been diligent to adapt the way it operates its system in order to
integrate PURPA energy. At the end of the day, the Company is still obligated to
produce reliable, fair-priced energy for its customers. Moreover, it has to operate within
its regulatory framework, but while doing so must be conscientious as to environmental
issues, cost recovery risk, and other various issues that must be considered when
striking an appropriate balance.
IDAHO POWER COMPANY'S PETITION TO MODIFY TERMS AND
CONDITIONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS - 16
III. DISCUSSION
A. PURPA Cogeneration and Sma!! Power Production Has Been Successfullv
Encouraged and Promoted on ldaho Power's Svstem.
Congress enacted PURPA to encourage the development of cogeneration and
small power production facilities, and directed FERC to promulgate regulations to
further this goal. 16 U.S.C. $ 824a-3(a); FERC v. Mississippi, 456 U.5.742,750-51,
102 S.Ct. 2126,72 L.Ed.2d 532 (1982). With the Energy Policy Act of 2005, Congress
directed amendments to PURPA, which included a new Part M exempting utilities in
designated Regional Transmission Organizations ("RTOs") from PURPA's purchase
requirements. 42 U.S.C. S 13201, ef seg. Additionally, federal regulations provide that
any state regulatory authority, with respect to any electric utility over which it has
ratemaking authority, may apply to FERC for a waiver from the application of any of the
requirements of the regulation of purchases and sales between a QF and electric
utilities. 18 C.F.R. $ 292.402(a). FERC must grant such waiver if the state regulatory
authority demonstrates that compliance with any of the requirements of the regulation of
purchases and sales between a QF and electric utilities "is not necessary to encourage
cogeneration and small power production and is not otherwise required under section
210 ol PURPA." 18 C.F.R. S 292.402(b).
ldaho Power has a long history with active PURPA QF projects. The first QF
projects were constructed and started selling their output to ldaho Power under PURPA
in approximately 1982. Allphin, Ex. 1. For the next 20 years, ldaho Power accumulated
a large number of predominately smal! hydro PURPA QF projects that steadily
increased and maintained energy deliveries under 200 MW total generation. /d. To this
day, small hydro QFs make up the majority of the number of PURPA projects under
IDAHO POWER COMPANY'S PETITION TO MODIFY TERMS AND
CONDITIONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS. 17
contract with ldaho Power. Allphin, Ex.2. ldaho Power has 68 PURPA hydro projects
out of a total of 133 PURPA projects under contract. ld. PURPA hydro, however,
provides a relatively smal! amount of the total PURPA generation. ld. PURPA hydro
provides approximately 154 MW of the 1,302 MW of total PURPA nameplate generation
capacity. ld. Since about 2002, and after the Commission increased the maximum
contract term from five years back to 20 years (Case No. GNR-E-02-01), ldaho Power
has experienced a dramatic increase in the number and size of PURPA projects,
predominately wind, and now solar, QF projects coming on-line and under contract.
As shown in Mr. Allphin's Exhibit No. 2, as well as the table below, Idaho Power
currently has a total of 1,302 MW of PURPA QF projects under contract. Allphin, Ex. 2.
Of that total, 781 MW of capacity from these projects are on-line and operational today.
ld. ldaho Power has 577 MW of PURPA wind capacity currently operating on its
system, with an additional 50 MW under contract to be on-line in 2016. ld. The
Company has 461 MW of PURPA solar capacity under contract to be on-line in 2016,
and an additional 885 MW of PURPA solar capacity in the queue actively seeking
PURPA energy sales agreements to be on-line in 2016. Allphin, Ex. 1; Ex.2. ln total,
ldaho Power today has 2,187 MW of PURPA generation operating, under contract, or
currently requesting long-term, fixed-price energy sales agreements to be on-line in
2016. td.
il
u
H
lt
IDAHO POWER COMPANY'S PETITION TO MODIFY TERMS AND
CONDITIONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS - 18
Renewable Energy
PURPA
On{ine and Under Contract
Biomass
CoGen
Thermal
Hydro
Wind
MW Subtotal
29
16
15
144
577
781 781
Under Contract, but NOT On-line
Hydro
Wind
Solar
10
50
461
Pending (Not Under Contract, Not On-!ine)
Solar
521 1,302
885
2,187
Non-PURPA
On-line Power Purchase Agreements
Geothermal
Wind
136
Total Renewable Energy - PURPA and Non-PURPA 2,323
ldaho Power also has an additional 136 MW of non-PURPA renewable
generation under contract. The Company's non-PURPA renewable projects consist of:
Elkhorn Wind, 101 MW; Nea! Hot Springs Geothermal,22 MW; Raft River Geothermal,
13 MW; and the Oregon Solar Photovoltaic Pilot Program, 55 projects with 0.42 MW.
Allphin, Ex.2.
IDAHO POWER COMPANY'S PETITION TO MODIFY TERMS AND
COND]TIONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS - 19
mw
35
101
Subtotal
136
The current customer obligation of $2.6 billion for all PURPA generation currently
operating on ldaho Power's system would increase to $6.3 billion with the addition of
the PURPA solar generation that is currently under contract and proposed. Allphin, Ex.
3; Ex. 4; Ex.9. This additiona! obligation and risk borne by customers is being added to
the Company's system at a time when it does not need any additional generation
resources to serve customers' needs and when the Company already has sufficient
renewable resources that would exceed the RPS requirements of ldaho Power's
neighboring states and California. Allphin, Ex. 5. The purpose of encouraging and
promoting the development of cogeneration and renewable power production facilities
has been exceedingly met for Idaho Power.
B. The Continued Acquisition of Larse Amounts of Unneeded lntermittent
PURPA Generation Inflates Power Suoplv Costs and Deqrades the
Reliabilitv of ldaho Power's Svstem.
1. PURPA Power Supply Expense. PURPA requires that the price for the
mandatory purchase of QF generation be set at the utility's avoided cost; i.e., the cost to
the electric utility of the electric energy which, but for the purchase from such QFs, such
utility would generate or purchase from another source. The Commission has recently
implemented changes to the avoided cost pricing methodology for projects that exceed
the published rate eligibility cap to utilize the incremental cost IRP avoided cost
methodology. Order No. 32697. This methodology uses the proposed QF project's
estimated hourly generation profile over a one-year period compared to ldaho Power's
resource stack from its AURORA power model. For each hour that the QF proposes
delivering generation to the Company, the methodology assigns the cost of the highest
cost Idaho Power displaceable resource serving load in that same hour as the hourly
IDAHO POWER COMPANY'S PETITION TO MODIFY TERMS AND
CONDITIONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS - 20
avoided cost. These hourly prices are accumulated into monthly heavy load and light
load prices, which become the prices contained in the energy sales agreement.
The Commission stated in each of its most recent 11 orders approving PURPA
solar contracts that it is pleased with the progression of the IRP methodology but that
price is not the only term to the required PURPA purchase. See fn. 2. ldaho Power
agrees with the statements. ldaho Power shares the Commission's concern that
significant and substantial requests for additional energy sales agreements with PURPA
QFs continue, unchecked by the pricing methodology and not burdened with meeting
any requirements of need. The Commission suggested that some of the terms and
conditions of PURPA energy sales agreement may need modification; ldaho Power
agrees. The continued and unchecked addition of extremely large amounts of
intermittent wind and solar QF generation onto ldaho Power's system at long-term,
fixed-rate prices when the Company has no need for the additional generation inflates
power supply costs borne by customers and degrades the reliability of the system. This
is contrary to and inconsistent with all of the requirements that exist for ldaho Power to
acquire non-PURPA generation resources. !f the Company were to seek regulatory
approval to construct 1,300 MW of solar generation, it would not be approved because
of the current resource sufficiency and cost. Likewise, there is no justification for long-
term PURPA contracts for that generation. ldaho Power is required to meet customer
needs with the least cost, most reliable resource. Customer impacts are not held
neutral when the standards for acquisition of PURPA resources are not aligned with the
standards for acquisition of Company-owned resources.
IDAHO POWER COMPANY'S PETITION TO MODIFY TERMS AND
CONDITIONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS - 21
Regardless of the methodology that is employed to estimate the utility's avoided
cost, it remains an estimate that will have variation from actua! costs. Moreover, at a
time of unprecedented changes in the technological, economic, and regulatory
landscapes faced by the electric industry today, accurately forecasting future power
costs is more difficult than ever. This fact, in and of itself, demonstrates why the risk
and potential harm increases the longer the price estimates are locked in. This
becomes compounded by federal constraints that prevent any update, change, or
modification to the contractual rates, once locked in for the fu!! term of the contract.
PURPA power supply expenses are growing at a rapid pace and becoming quite
large. The graph below, which is reproduced from Mr. Allphin's Exhibit No. 7, shows the
historical and projected increase in annua! PURPA power supply expense from 2004
through 2025, and includes a!! contracts signed and approved by the Commission
through December 31, 2014.
As shown in the graph above, annual PURPA power supply expenses in 2004
were approximately $40 million. Allphin, Ex.7 . 2004 approximates the beginning of the
IDAHO POWER COMPANY'S PETITION TO MODIFY TERMS AND
CONDITIONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS -22
ldaho Power PURPA Payments
.Ago
=(t\
250
200
150
100
50
0
,".""d"-."".$"-.t,-f "st"d)"d}"-f "d"f "$st""-$"+t"d"et.,-f "dPrdP"-f, "S
addition of large-scale PURPA wind, under 20-year,long-term, fixed-rate contracts to
ldaho Power's system. The Commission increased the five-year maximum contractual
term to 20 years in 2002. Order No. 29029, Case No. GNR-E-02-01. lt took more than
20 years of the accumulation of PURPA contracts to reach the $40 million in costs seen
in 2004. Just five years Iater, in 2009, the annual power supply expense grew by 50
percent to approximately $60 million. As more wind was coming onto the system at a
rapid pace, just three years later, in 2012, annual PURPA power supply expense almost
doubled, to nearly $120 million, and eventually levels off for a few years just under $150
million. With the rapid addition of the recent PURPA solar contracts, which are
contracted to come on-line by the end of 2016, by 2018, PURPA annual power supply
expense is estimated to increase to just below $200 million and increase to just under
$230 million by 2025. This is a staggering 575 percent increase in annual PURPA
power supply expense in approximately 20 years, over the previous 20 years. This
growth trend continues during a time when ldaho Power has no identified need for new
generation resources identified by its lRP. The Company is capacity sufficient through
2021, and energy sufficient beyond the next 20 years.
ldaho Power's average cost of PURPA generation included in base rates is
$62.49/MWh. This price is always high when compared to current alternatives. ldaho
Power's avoided cost, established through the avoided cost methodologies approved by
the Commission, has historically exceeded market price, and is projected to always
exceed market price into the future as shown in the graph below which is reproduced
from Mr. Allphin's Exhibit No. 10.
IDAHO POWER COMPANY'S PETITION TO MODIFY TERMS AND
CONDIT]ONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS - 23
E
==.(r)
Average PURPA Price vs. MidC lndex
95
85
75
65
55
45
35
25
15
2016 2018 2020 2022 2024 2026 2028 2030 2032 20342000 2002 2004 2006 2008 2010 201,2 20t4
Mid C Historical
The cost of PURPA generation contained in base rates, on a dollars per MWh
basis, is not just greater than Mid-C market prices, it is greater than all the net power
supply cost components currently recovered in base rates: FERC Account 501, Coal;
FERC Account 547, Natural Gas; FERC Account 555, Non-PURPA Purchases; and
FERC Account 447, Surplus Sales. Allphin, Ex. 8. At $62.49 per MWh, the average
cost of PURPA purchases is greater than the average cost of coal at $22.79 per MWh,
greater than gas at $33.57 per MWh, greater than non-PURPA purchases of $50.64 per
MWh, and significantly greater than what is being sold as surplus sales at $22.41 per
MWh. /d. This economic relationship between PURPA and the Company's other power
costs illustrates that as the Company is required to purchase unneeded PURPA
generation, it may be required to back down or curtail other less expensive sources of
generation or market purchases in order to continue purchasing PURPA generation at a
IDAHO POWER COMPANY'S PETITION TO MODIFY TERMS AND
CONDITIONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS - 24
higher cost. This would mean that the Company's overall net power supply expense, on
a dollars per MWh basis, would increase, adversely impacting customers.
2. Reliability of the System. The Commission stated in its recent PURPA
solar orders that it was concerned about the Company's ability to balance the
substantia! amount of must-take intermittent generation and still reliably serve
customers. See fn. 2. ldaho Power shares this concern. The Company already
experiences reliability curtailments of generation in order to maintain reliable operations
with the integration and management of the existing 781 MW of must-take PURPA
generation. ldaho Power's hydroelectric and coal generation has must-run levels that
the Company cannot go below without violating environmental regulations relating to the
hydro facilities or taking the coal generation off-line and thus making it unavailable to
meet required loads until it could be restarted. With the addition of the must-take
PURPA generation, which is less predictable than firm generation and does not even
equate to non-firm generation as it is unscheduled and delivered if, when, and in
whatever amount the QF determines, the Company's system can rapidly move to an
imbalance position, in this case over generation, and must take remedial actions. If
remedial actions are not available, or not employed in a timely manner, then the
Company can have system reliability violations, events, and/or outages and damage.
Over the last several years, reliability curtailments of PURPA generation have been
necessary in order to maintain the integrity of ldaho Power's system. For the period
from May 201 1 through December 2014, the Company had at least 15 reliability events
that resulted in wind generation output reductions in order to maintain the reliable
operation of the Company's electrical system. These curtailments, or generation
IDAHO POWER COMPANY'S PETITION TO MODIFY TERMS AND
CONDTTIONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS.25
limitation set points, have been relatively infrequent, for relatively short durations, and
are removed as soon as possible once it can safely be done and maintain a balanced
system.
Tota! load on ldaho Power's system varies from a minimum of approximately
1,100 MW to a maximum of approximately 3,400 MW throughout the year.s ldaho
Powerdid a comparison using the estimated system load for 2016 and 2017, including
ldaho Power's must-run minimum generation from its hydro and coal generation and
must-take generation from existing PURPA. This analysis is provided as Exhibit No. 6
to Mr. Allphin's direct testimony and includes a graph depicting these resources and
load for the first week of each month during 2016 and 2017. Without the inclusion of
any gas-fired generation, and including only the Company's must-run coa! and hydro
generation, without any of the must-take PURPA generation whatsoever, that
generation is projected to exceed load tor 14 percent of all hours during 2016 and 2017.
Allphin, Ex. 6. The Company's must-run hydro and coal generation combined with
existing must-take PURPA, but without any of the recently approved PURPA solar
generation, exceeds tota! system load for approximately 29 percent of all hours during
2016 and 2017. ld. When the 461 MW of PURPA solar that is under contract and
scheduled to be on-line in 2016 is included, ldaho Power's must-run and must-take
generation exceeds total system Ioad for approximately 33 percent of all hours in a
year. ld. Finally, inclusion of the additional 885 MW of proposed PURPA solar
generation increases the frequency of must-run and must-take generation in excess of
load to 40 percent of all hours during 2016 and 2017. ld. Each one of these hours
creates a potentia! over-generation event where remedial action of some kind will be
5 Actual numbers tor 2O14were approximately 1,073 MW minimum and 3,184 MW peak
IDAHO POWER COMPANY'S PETITION TO MODIFY TERMS AND
CONDITIONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS - 26
necessary to keep the system in balance and meet the obligation to reliably serve
customers. The historica! and projected market price for surplus sales has always
been, and is projected to always be, much lower than the price the Company pays for
PURPA. Allphin, Ex. 8; Ex. 10. lf transmission capacity is available to conduct off-
system sales, the Company would sell at a loss. Allphin, Ex. 8 (showing average cost
of PURPA at $62.49 and average surplus sales price of $22.41). When the Company
has no identifiable need for any additional generation, each one of these potential
reliability events is a completely unnecessary destabilization of ldaho Power's system,
putting its required service to its customers at risk.
C. The Lonq-Term Lock in of Contractual Rates for 20 Years is Uniust.
Unreasonable. and Contrarv to the Public lnterest.
The state of ldaho has a chosen, authorized, and constitutional system of
regulation designed to protect the public interest of the citizens of the state of Idaho and
to allow for companies like ldaho Power to reliably provide a vital service to the public.
See ldaho Code S 61-101 et. seq.; /daho Power & Light Co., v. Blomquist et al., 26
ldaho 222, 141 P.1083 (1914). Our state's system of regulation, as it pertains here to
the utility acquisition of generation resources, is being undermined by PURPA.
There is a fundamental disconnection between the way a regulated monopoly
service provider, like ldaho Power, must plan for and acquire generation resources and
the PURPA mandatory purchase requirement. The major gap between these two
regulatory processes and requirements is the determination of NEED.
lt
lt
lt
]DAHO POWER COMPANY'S PETITION TO MODIFY TERMS AND
CONDITIONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS -27
IRP/Risk Manasement
Pol icv/Certificate of Pu bl ic
Convenience and Necessitv ("CPCN")
-vs-
PURPA
Meet need (load) with least cost, most
reliable resource(s)
NEED
Utility + QF = FERC mandatory
purchase
No determination of Need,
Price options at election of QF
IRP - Z0-year planning horizon,
refreshed every two years
Request for Proposals, Competitive
Bidding
As-Delivered - market index price,
continuous term (effective until
terminated on 60 day's notice)
CPCN - required to build new resources
- additiona! scrutiny, Commission
determination
20 year lock in of estimated avoided
cost rate - no ability to
change/adjust price
RMP - transactions do not exceed 18
months - transactions of 2 years or
more, Commission approval
Gommission approval or rejection of
contract - or - Commission
determination of legally enforceable
obligation
As a regulated utility providing retail electric service to consumers in the state of
ldaho, ldaho Power has strict requirements it must meet in order to acquire generation
resources, which are set and overseen by the Commission. In order to acquire
generation resources ldaho Power either (1) builds a generation resource that it owns
and operates for the benefit of its customers or (2) purchases generation through a
bilateral contract with another entity, makes a market purchase, and makes mandatory
PURPA QF purchases.
Under the requirements of the Commission's regulation, ldaho Power's
acquisition of utility-owned generation starts with the IRP process. The IRP must
identify a need for a generation resource, and further identify the proper resource to
IDAHO POWER COMPANY'S PETITION TO MODIFY TERMS AND
CONDITIONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS - 28
meet that need in the least cost, most reliable manner, given the known environmental,
operational, and other constraints. Then the utility would conduct a request for
proposals and a competitive bidding process to select the most appropriate resource to
bring to the Commission for approval. ln order to construct new generation resources,
the Company must obtain a CPCN from the Commission for that resource. ldaho Code
S 61-526. Beyond the Commission's required public and regulatory processes
associated with the lRP, the CPCN process subjects the decision to acquire that
resource to additional Commission and public scrutiny, and assures that the utility only
acquires those resources that serve a need in the least cost, most reliable manner
available, and that acquisition of that resource is in the public interest. Additionally,
should a proposed resource make it through the IRP and CPCN processes, there are
additional Commission proceedings required to include the cost of that resource into
rates and establish how those costs will be passed on to customers. The IRP is filed
with and reviewed by the Commission every two years. Changes in conditions,
positions, market prices, gas forecasts, load forecasts, etc., are incorporated and
captured continually as they happen during the continuous development of the lRP and
its every other year filing. Those decisions and inputs are not locked in for 20 years
with no ability to adjust, update, or change, like PURPA transactions.
With regard to market purchases of generation resources to serve load or any
other energy market transactions of purchases and sales that the Company conducts, it
must comply with the Commission-approved risk management policy. The Company's
risk management policy, set up to govern the risk and customer exposure to market
fluctuations when the Company makes power purchases and sales on the market has
IDAHO POWER COMPANY'S PETITION TO MODIFY TERMS AND
CONDITIONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS.29
short-term limitations. Under its authorized and required risk management policy, the
Company does not enter into transactions beyond 18 months. lf the Company were to
desire to transact for any periods of two years or more, specific Commission
authorization and approval is required. This policy has been deemed a prudent process
for managing customer exposure to the market and transactional risk with making
generation purchases and sales, and the prudent term is far below the 20 years
required for mandatory, unchangeable PURPA purchases.
ln stark contrast to the many Commission processes, proceedings, and
protections that are in place and required for the utility to construct, own, and operate a
generation resource for the benefit of its customers, the PURPA transaction has none.
The only requirement in the mandatory PURPA purchase of generation is that ldaho
Power is a regulated public utility providing retail service to customers and the other
party is a PURPA QF. lf so, and regardless of whether the resource is needed or not,
the utility must purchase the generation. PURPA contains no guidance and no
limitations as to whether or not the utility actually needs the QF generation resource that
it is required to purchase. Similarly, PURPA contains no limit or cap on the amount of
PURPA QF generation that the utility must purchase under that mandatory obligation of
PURPA. These problems are amplified and exacerbated where the utility is required to
purchase for a long term with fixed rates.
D. The Commission Should Reduce the Currentlv Authorized 20-Year
Contractual Term to a Maximum of Two Years.
As referenced above, the Commission has changed the authorized maximum
term of a required PURPA purchase several times throughout is implementation of
PURPA in the state of ldaho The Commission has authorized maximum contract terms
IDAHO POWER COMPANY'S PETITION TO MODIFY TERMS AND
CONDITIONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS - 30
varying from an initial 3S-year contract, to 20 years, then five years, then back to 20
years. Since the currently authorized 2O-year contract term has been in place (2002),
ldaho Power has seen waves of rapid, large-scale additions of wind, and now solar, QF
generation.
A major consideration that must go into the determination of the appropriate
maximum contract term must be the fact that once a contract is approved and put in
place by the Commission that it is an absolute lock in of the rates included in that
contract for the entire term. lt does not matter to what extent or degree the contractual
rates vary from actua!, vary from changed forecasts or assumptions, or any other
changed circumstances. The contractual obligation is set and fixed for the entire
duration of the term of that contract. Coupled with the reality that the one-sided
mandatory purchase is initiated by the QF if and when the QF determines, when the
right set of conditions around price, forecasts, fluctuations in natural gas prices, etc., are
most favorable to the QF, these long-term obligations are almost always locked in to the
detriment of ldaho Power and its customers.
The Company is not able to acquire any other generation or purchased power
that is indiscriminately locked in for such long terms. If the Company does acquire any
non-PURPA generation or purchases longer than two years, it comes with specific
Commission determinations of meeting a need in the least cost, most reliable manner
available. These determinations are made only after careful examination and process,
including various public processes and proceedings, such as through the IRP pro@ss,
a CPCN proceeding, rate base proceedings, and other specific Commission
proceedings and determinations that assure customers are protected and the Company
IDAHO POWER COMPANY'S PETITION TO MODIFY TERMS AND
CONDITIONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS - 3,1
meets its obligations to reliably serve. lt does not follow that a PURPA transaction, that
does not have the benefit, requirement, or protections associated with all of the
previously mentioned Commission processes and procedures, and must be acquired
regardless of need, would be indiscriminately locked in with long-term, fixed costs.
The IRP utilizes a 2O-year planning horizon. At first blush, this appears to
coincide with the 20-year term of a required PURPA transaction. However, this is
definitely not the case. The IRP is continually updated, refreshed, and, if necessary,
changed. The IRP incorporates public input into its development and is filed for the
Commission's review and acknowledgment every two years. The only way that the
Commission could assure that a mandatory PURPA contractual transaction would get
refreshed at least as often, would be to limit the maximum term to two years. The
Company's obligation to purchase from the QF would remain after the two year term,
but changed circumstances, inputs, forecasts, and prices could be incorporated into the
mandatory purchase, and not locked in for 20 years based upon forecasts and
assumptions that can quickly become stale and disconnected from reality.
It is not just the IRP in which it has been deemed prudent to update prices and
transactions on a basis more frequently than 20 years. As previously discussed, the
Company does not enter into transactions past 18 months pursuant to its approved risk
management policy and transactions for any periods of two years or more require
specific Commission authorization and approval. lt has been deemed prudent and in
the public interest to update and refresh the IRP and its decisions about the need to
acquire additional generation every two years. Similarly, it has been deemed prudent
and in the public interest not to expose customers to market and price risk in non-
IDAHO POWER COMPANY'S PETITION TO MODIFY TERMS AND
CONDITIONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS - 32
PURPA purchase and sales transactions under the Company's approved risk
management policy. The risk and exposure that customers are exposed to with a
required PURPA transaction is even greater because of the federa! constraints that
prohibit the adjustment of rates and contractual terms for the duration of the contractual
term, once put in place. The authorized maximum term for PURPA energy sales
agreements with ldaho Power should be limited to two years, to better align with the
exposure of customers to risk that has been deemed prudent for the IRP process and
the Company's risk management policy.
ln PURPA exempt jurisdictions such as RTOs where utilities are exempt from
PURPA's mandatory purchase, QFs and other independent power producers do not
have access to 20-year, long-term, fixed-price transactions. Attachment t hereto
contains a copy of the previously sworn, admitted, and cross-examined direct testimony
of William H. Hieronymus from Case No. GNR-E-11-03. Mr. Hieronymus provided
testimony regarding various implementations of PURPA throughout the country,
including discussion of alternative market-based avoided cost mechanisms and
available transactions in PURPA exempt jurisdictions. He testified, "No RTO requires
any load serving entity to purchase energy bilaterally on a long-term basis and the
longest term for a guaranteed capacity price in any RTO is three years." Hieronymus,
Direct, p. 56. Mr. Hieronymus, in discussing visible market prices for calculating
avoided cost prices, testified about the lack of availability of long-term transactions for
QFtype projects in PURPA exempt jurisdictions:
the Energy Policy Act of 2005 mandated that utilities in the
five original RTOs were eligible for exemption from PURPA
section 210 altogether. Hence, projects that previously
would have been QFs in those areas are dependent on
IDAHO POWER COMPANY'S PETITION TO MODIFY TERMS AND
CONDITIONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS - 33
either bilateral contracts with utilities or the visible markets
conducted by the RTOs for revenue. Most such contracts
are short run in nature; state-supervised auctions typically
are for three years or less. RTO power markets are even
shorter term, with prices varying even within the hour and
prices set at most a day ahead. Capacity typically is bought
on a monthly, seasonal, or annual basis in those RTOs that
have capacity markets. Power markets are also used in
several instances to set avoided cost rates where the utility
is not exempt. California is one example. Energy prices for
QFs except the smallest ones are set based on one year
fonruard market prices.
Hieronymus, Direct, pp. 83-84. Mr. Hieronymus also testified about how California
revised its state PURPA implementation in response to overwhelming amounts of
proposed PURA generation that exceeded 16,000 MW. ld., pp. 72-83. Energy
payments during the term of QF contracts in California are reset annually, rather than
fixed in advance for the term of the contract. ld., pp. 78-79.
When looking at the present amount of PURPA solar generation that has
contracted with or is seeking to contract with ldaho Power, the additional obligation, risk,
and price differential between a 2O-year and a two-year fixed-price contract term is
staggering. The 461 MW of PURPA solar currently under contract has a 20-year
obligation of approximately $1,665,000,000. Allphin, Ex. 4; Ex. 9. The same 461 MW
of PURPA solar would have an associated obligation passed on to customers if limited
to a two-year term of $92,834,000. Allphin, Ex. 9. The 885 MW of proposed PURPA
solar contains an estimated 2}-year obligation of approximately $2,102,000,000,
whereas the total obligation for the same 885 of proposed PURPA solar with a two-year
term is approximately $103,600,000. Allphin, Ex. 3; Ex.4.
IDAHO POWER COMPANY'S PETITION TO MODIFY TERMS AND
CONDITIONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS.34
IV. CONCLUSION
The required term of a mandatory purchase of PURPA generation is within the
authority and discretion of the Commission to determine and set. The Commission has
modified the required term of PURPA purchases several times in the past, and most
recently implemented a 2O-year maximum term in 2002. Since that time, ldaho Power
has seen exponential growth in the addition of must-take PURPA generation, primarily
in large rapid waves of PURPA wind and solar generation. This will inflate annual
PURPA power supply expenses by more than 575 percent over 2004 levels, and has
come at a cost to system reliability and to ldaho Power's customers. ldaho Power now
has 2,187 MW of PURPA generation on-line, under contract, or proposed for its
system-a system that has minimum loads of approximately 1,100 MW and maximum
peak loads of approximately 3,400 MW. The purpose of promoting and encouraging the
development of cogeneration and small power production has been met for ldaho
Power.
ldaho Power has no currently identifiable need to acquire additional generation.
The Company is capacity sufficient through 2021, and energy sufficient through 2035.
Additionally, the planned Boardman to Hemingway transmission line would serve
additional growth for years beyond that without adding any new power plants. The
Company's currently existing must-run coal and hydro generation, along with currently
existing and operating must-take PURPA generation (without the inclusion of any solar)
exceeds estimated total system load for 29 percent of all hours during 2016 and 2017.
The addition of the 461 MW of PURPA solar under contract increases the frequency of
must-run and must-take generation that exceeds load to 32 percent of all hours during
2016 and 2017, while the addition of 1346 MW of the additional PURPA solar
IDAHO POWER COMPANY'S PETITION TO MODIFY TERMS AND
CONDITIONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS - 35
generation both under contract and proposed increases that frequency to 40 percent of
all hours. Each one of these hours creates a potential over-generation event where
remedial action of some kind will be necessary to keep the system in balance and meet
the obligation to reliably serve customers. When the Company has no identifiable need
for any additional generation, each one of these potential reliability events is a
completely unnecessary destabilization of ldaho Power's system, putting its required
service to its customers at risk.
The acquisition of any Company-owned generation resource, as well as the
Company's purchase and sale of non-PURPA generation, is either limited to terms less
than two years or is subject to intensive Commission and public participation, scrutiny,
process, and proceedings to determine that the Company is acting prudently, in the
public interest, and fulfilling a need in the least cost, most reliable manner possible.
These requirements, particularly that of establishing need for the resource, are absent
in a mandatory PURPA QF purchase. The further constraint imposed by PURPA that
eliminates any ability to modify, adjust, or change the prices that are locked into a
PURPA energy sales agreement for the duration of that contract's terms, regardless of
whether all costs were included or whether actual costs and conditions changed or
varied, makes long-term, 2O-year contract terms at best risky, and in ldaho Power's
case harmful.
V. PRAYER FOR RELIEF
WHEREFORE, ldaho Power respectfully requests:
1. That the Commission issue an order directing that the maximum required
term for any ldaho Power PURPA energy sales agreement be reduced from 20 years to
two years; and
IDAHO POWER COMPANY'S PETITION TO MODIFY TERMS AND
CONDITIONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS - 36
2. That the Commission direct any other relief deemed appropriate and in the
public interest.
Respectfully submitted this 30th day of January 2015.
IDAHO POWER COMPANY'S PETITION TO MODIFY TERMS AND
CONDITIONS OF PROSPECTIVE PURPA ENERGY SALES AGREEMENTS - 37
Attorney for ldaho Power Company
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
GASE NO. IPC-E-I5-01
IDAHO POWER GOMPANY
ATTACHMENT 1
RECEIVED
?0r? JIH 3l Pll 3: 23
lDA.t"iC rU;lr.if;
uTl LiTi E 5 c ol'{ i'{ i $s rc i{
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OE THE COMMISSION'S
REVIEIiI OF PURPA QF CONTRACT
PROVISIONS INCLUDING THE SURROGATE
AVOIDED RESOURCE (SAR) AND
INTEGRATED RESOURCE PLANNING (IRP)
METHODOLOGIES EOR CALCULATING
PUBLISHED AVOIDED COST RATES.
CASE NO. GNR-E-1.1--03
IDAHO POWER COMPANY
DIRECT TEST]MONY
OE
WTLLTAM H. HIERONYMUS
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I. IITIIRODUCTION
O. Please state your name and business address.
A. My name is William H. Hieronymus and my
4 business address is 200 Clarendon Street, T-32, Boston,
5 Massachusetts 02L\6.
o.
A.
By whom are you employed and in what capacity?
I am a Vice President of Charles River
8 Associates, Inc., an international economics and management
9 consulting company.
10 O. Please describe your educational background
11 and work experj-ence.
LZ A. I am an economist with a doctoral degree from
l-3 the University of Michigan and have spent the past 36 years
14 specializing in the economics and regulation of electric
15 utilities. I have worked extensively with utilities
16 throughout the U.S. and abroad on matters such as system
L7 planning, assets valuation, rate design, procurement
18 design, risk management, Ioad forecastlng, and response to
19 regulatory policies. I have testified numerous times
20 before state utility commissions, the Federal Enerqy
2L Regulatory Commission (*FERC"), courts, arbitrators, and
22 legislative bodies on these topics and on policy matters
23 such as price regulation, competitive market design, market
24 power, the prudence of utility decisions, stranded costs,
25 and so forth. In the 1980s I heJ-ped utilities and
HTERONYMUS, DI 1.
Idaho Power Company
1 regulators in complying with the requirements of Public
2 Utility Regulatory Pollcies Act of L978 (*PURPA"). This
3 included compliance with PURPA Section 210 that governed
4 purchases from and sales to qualifying facilities (*QE").
5 My resume is attached as Exhibit No. 6.
6 Q. What is the purpose of your testimony in this
7 matter?
B A. I have been asked by ldaho Power Company
9 ("Idaho Power" or "IPC") to provide an overview of
10 experience with PURPA Section 210 and to suggest lessons
lL relevant to the ldaho Public Utilities Commission's
12 ("Commission") current review and reconsideration of its
13 PURPA Section 210 implementation. While I am generally
14 aware of ldaho's recent and current PURPA implementation
15 and experience, I also recognize that Idaho PURPA history
16 is very familiar to the Commission and participants in this
l7 proceeding. Hencer ry focus is not primarily on the Idaho
18 experience but rather on experience wlth PURPA generally.
19 I also have been advised that the predominant focus
20 of this phase of the Commlssion' s reconsideration of PURPA
2L implementation is on the methodology for computing avoided
22 costs and the application of it to QEs of different sizes
23 and types. Accordingly, my testimony focuses on avoided
24 cost methodology and its application. I also understand
25 that the scope of consideration of avoj-ded cost does not
HIERONYMUS, DI 2
Idaho Power Company
1 extend to market-based methods for meeting PURPA
2 requirements, such as competitive procurements of power
3 supplies and palrment of market prices as alternatives to
4 administrative/regulatory methods of setting avoided cost
5 prices. I nonetheless will dj-scuss use of these methods
6 for two reasons. First, Idaho may choose to consider their
7 use to at least some degree. Second, the fact that such
B methods can and have been used to satisfy the requirements
9 of PURPA Section 2l-0 illuminates what the section requires
10 and hence provides guidance concerning what is essential
11 (and non-essential or even inappropriate) if administrative
L2 avoided cost methods as designed for PURPA compliance.
13 Consistency between the requirements of PURPA and
1,4 state implementations of Section 210 depends primarily on
1-5 how avolded cost is defined and implemented. However,
L6 aspects of state implementatj-on other than avoided cost
L7 calculation are at least as critical to the consequences of
1B PURPA, particularly elements of implementation that affect
L9 the risk that QF payments will diverge substantially from
20 actual avoided costs for prolonged periods as weII as the
2L related risk that Idaho utilities will be compelled to
22 contract for QF power in amounts that materially exceed
23 thej-r needs. I therefore also will discuss experience with
24 and concepts relating to these other aspects of PURPA
25 implementation.
HIERONYMUS, DI 3
Idaho Power Company
1 lastly, I have been asked to review and comment upon
2 Idaho Power's proposal for a new avoided cost methodology
3 to be used in ldaho.
4 Q. Could you summarize how your testimony is
5 presented?
6 A. Yes. I first will summarize my conclusions
7 and recommendations. This section also contains the
I results of my review of the Idaho Power proposal for
9 changes from the current avoided cost methodology. Next, I
10 will discuss the historical development of PURPA
1l- implementation and how it has changed and evolved over
L2 time. f then will discuss various types of avoided cost
l-3 methodologies employed by different states and regions to
t4 meet the requirements of PURPA. f then make
15 recommendations regarding proper methodologies for
16 establishing avoided cost rates, and make suggestions for a
l7 proper implementation of an administrative/regulation-based
18 avoided cost calculation. I also discuss other issues
19 related to power purchase agreements with PURPA QFs,
20 particularly the risk allocation and/or risk shifting
2L between the QF developer and the utility's customers which
22 relates to the length of the contractual term and nature of
23 the pricJ-ng mechanism in the contract.
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HTERONYMUS, Dr 4
Idaho Power Company
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II. ST'IOIAR,I OF COITCLUSIONS AND RECODOIENDAIIOI{S
O. Could you please summarLze the conclusions and
3 recommendations of your testimony?
A. Yes. My testimony will discuss and conclude
5 that:
6 L. It is essential to
7 the purpose of PURPA which was l-imited
not
to
Iose sight of
ending
I discrimination against cogeneration and small renewable
9 power facilities. This limited purpose is underscored by
l-0 the statutory provision that prices paid shall not exceed
L1 the utility's avoided cost, Not only was PURPA not meant
L2 to subsidize QEs at the expense of customers, such
13 subsidies are in fact illegal if provided through PURPA QF
L4 prices.
15 Z.Avoiding large differences between
16 PURPA rates set when contracts are signed and actual
l7 avoided cost is very important. History demonstrates that,
l-8 overall, prices paid for PURPA power much exceeded costs.
19 this arose in part from a pro-QE regulatory bias in at
20 least some states, but also from unfortunate large errors
2L in fuel and power market forecasts. Such large errors are
22 harmful whether prlces are too high or too 1ow. The errors
23 that occurred caused hiqh profits for developers and
24 unnecessarily high prices for consumers. Had the errors
25
H]ERONYMUS, DI 5
Idaho Power Company
1 been in the other direction, ratepayers would have had a
2 windfa1l, at least unti-I projects went bankrupt.
3 3. While some methods of setting avoided
4 costs are better than others and may reduce the range of
5 forecast error, no method of setting avoided cost can
6 prevent the potential for large forecast errors. The only
7 way to limit the difference between the actual value of QE
I power and prices paid for it is to keep contracts short
9 and/or severely limit the period for which prices are
10 fixed. This can be done in a number of ways, including
L1 reopeners and indexation.
L2 4. The risk of getting prices badly wrong
13 is compounded by the difficulty of limiting the quantity of
74 QF power. PURPA provides no direct authority to limit QF
15 purchases to the amount and type of power that is needed.
16 However, solutions have been found that substantiatly
L7 mitj-gate this open-ended obligation.
18 5. If prices paid are not only too high
l-9 but also higher than those paid in other jurisdictions, the
20 excess QF power seeking contracts in the high rate states
2l will be intensified. PURPA initially was focused on
22 cogeneration, which was thought to require a real host user
23 of steam and heat. Such hosts were immobile and limited in
24 number. In fact, PURPA project development has turned out
25 to be quite portable, with developers building where
HIERONYMUS, DI 6
Idaho Power Company
I conditions such as avoi-ded cost rates and contract terms
2 are most attractive.
3 6. AII states, at least initially, used
4 administrative methods/regulatory proceedings to set
5 avoided costs. This was reasonable and necessary given the
6 vertical integration of utilities and the Lack of
7 competitive or transparent markets for power. Unhappy
8 experience with administratively set avoided costs in the
9 early years after PURPA caused FERC and many utilities and
10 state regulatory commissions to seek alternatives,
11 primarily structured procurements such as requests for
1,2 proposals and "auctions" to select QF and other third-party
13 power projects.
L4 7. Many states first adopted proxy unit
15 methods that used the cost of either the next planned
'1,6 utility unit or a generic unit to establish avoided costs.
l7 This made logical sense given that utility planning was
18 primarily driven by capacity needs. However, it led
19 increasingly to mismatches between the costs avoided by not
20 building the proxy units and the costs avoided by the QF as
2L the nature of QFs changed from primarily QFs that operated
22 like the conventional utility units used as proxies to
23 quite dissimilar p1ant, such as energy limited,
24 intermittent energy producers. The Idaho Surrogate Avoided
25 Resource ("SAR") methodology is a proxy unit method.
HIERONYMUS, DI 7
Idaho Power Company
1 8. The other common administrative method
2 of establishing avoided cost is to use actual simulation of
3 the utility system to establish avoided cost, particularly
4 avoided energy costs. A common version uses the net cost
5 of a peaker to establish capacity cost and simulation of
6 operation of the utility's system to establish marginal
7 energy costs. 0F avoided cost rates are then based on the
B QF's forecasted capacity contribution and the amount and
9 timing of its energy production. A more complete and
1-0 complex version of this methodology simulates operation of
l-1 the system with and without the QF. Avoided energy costs
L2 is the difference "with and without" the QF; avoided
13 capacity costs may reflect changes in the resource plan as
74 it is adjusted to accommodate the QF. These simulation-
15 based methods are an important improvement on the proxy
16 unit method because they inherently base avoided costs on
l7 the output characteristics of the QF. What ldaho Power
LB cal1s the Integrated Resource Plan (*fRP") methodology
19 (both currently and as proposed) is a version of this
20 methodology.
2t 9. Another issue concerning PURPA
22 compliance is the use of fixed rate schedules to pay for QE
23 power. PURPA requires such schedules only for projects of
24 100 kilowatts ("kW") or Iess, but many states have extended
25 fixed offers to much larger units. fn many instances, the
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schedule is based on a proxy unit. Use of such schedules
should be sharply limited for two reasons: (a) the price
derived from a single proxy unit may be very
unrepresentative of the value of a particular QF and (b)
such inaccurate schedules can contribute to substantial
excesses of QF projects demanding contracts. This problem
is best mitigated by a combination of limiting the size of
projects that are eligible and by having multiple standard
offers, such that one of them reasonably corresponds to the
actual characteristics of the QF.
10. In enacting PURPA, Congress did not
anti-cipate the substantial restructuring of the utility
J-ndustry that took place in the 1990s. In much of the
country, restructuring made PURPA section 210 both onerous
and unnecessary. When it enacted the Energy Policy Act of
2005, which exempted utilities j-n regions with visible and
competitive organized power markets, Congress reinforced
that the intent of PURPA was only to assure non-
discriminatory treatment of QFs. The Act not only
eliminated PURPA obligations for utilities serving more
than half of the country, it also showed that Congress
believed that access to market prices was by itself
sufficient to comply with PURPA. This conclusion provi-des
important guidance on Congressional intent to those parts
of the country to which the exemptj-on does not apply.
HIERONYMUS, DI 9
Idaho Power Company
1 11. There now are multiple ways of setting
2 PURPA avoided costs including two market methods: (a)
3 access to competitive power markets and (b) the creation of
4 competitive procurements, and at least two types of
5 administrative determinations: (a) proxy units and (b)
6 IRP/system simulation methods. Market methods, where
7 available and applicable, have the virtue that they take
8 the potential for bias in setting avoided cost out of the
9 equation and reduce the amount of regulatory judgment
l-0 required. In exempt regions, and in some other cases, a
lL demonstration of QF access to markets has been sufficient
LZ to relieve the utility from all cost risks for QF power.
13 Among administrative methods, the lRP/system simulation
L4 methods have the considerable virtue that the energy
L5 savings attributed to the QF are calculated directly from
16 the dispatch of the QF rather than assuming
L7 counterfactually that its characteristics are those of a
18 quite dissimilar proxy unit. While more complicated than
19 proxy unit methods, simulation is within the capability of
20 all utilities and is particularly appropriate when non-
21, dispatchable, intermittent resources are a major source of
22 QF offers. The virtue of the proxy method is that it is
23 simple and relatively transparent.
24 12. My advice to the Idaho Commission
25 concerninq how to set avoided costs using
HIERONYMUS, DI L0
Idaho Power Company
1 administrative/regulatory methods flows directly from these
2 observations:
3 a. Use avoided cost calculation
4 methods that take into account the characteristics of the
5 QF unit and accurately model the timing, dispatchability,
6 firmness and amount of power produced by the QF at issue.
7 This requires using IRP-type methods for each unit or, in
I the case of smal1 units, creatlng IRP-based standard offers
9 based on the characteristics of similar generic units. It
l-0 also requires time differentiation of payments.
11 b. Sharply limit the applicability of
1"2 fixed standard offer price schedules, which PURPA only
13 requires for QEs of less than 100 kW. If Idaho chooses to
'L4 extend standard offers to larger units, it is even more
15 important that multip1e, technology-specific standard
16 offers be developed and used so as to avoid systematic
L'l biases in avoided cost rates and unlawful discrimination
1-8 among QFs and between QEs and other resources.
L9 c. Limit capacity payments to the
20 amount of capacity the QF actually displaces. When no
2L capacity is displaced, the payment should be zexo.
22 d. Limit customers' exposure to long-
23 term price risk by such mechanisms as not offering fixed
24 prices, usi-ng formula rates indexed to actual energy or
25 fuels prices, and shortened contract lengths. It is
HIERONYMUS, DI 11
Idaho Power Company
1 particularly important that consumers not take on price
2 risk for QF power that is not even used to serve them, but
3 rather is sold into the interchange market.
4 e. Seek to limit purchases of
5 unneeded QF energy and capacity. Quantity-limited requests
6 for proposals ("RFP") and auctions is one way to do this.
7 Properly reflecting the value of the specific QFs is
8 another. For price rationing to work, it is necessary that
9 avoided costs be reset as often as is necessary to reflect
l-0 the impact of prior QFs on avoided energy and capacity
l-1 values. Rationing based on pri-cing aside, this also is
L2 necessary if avoided costs are to be computed properly.
L3 FERC has noted that the attraction of too much QE power is
14 a signal that prices being paid are too high and should be
15 reduced. Including the successive amounts of QF power in
L6 the calculation is one way to do this, albeit not
L7 necessarily sufficiently.
18 O. You stated earlier that you had reviewed and
19 would comment on IPC's proposed changes to its QF avoided
20 cost rates and tariff provisions. What do you conclude
2L based on that review?
22 A. I have reviewed Idaho Power's proposal for
23 revising the Idaho avoided cost calculation and contract
24 terms. My review is at a relatively high level and does
25
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not extend to some
following:
of the details in it. f conclude the
1. The fact that QFs j-n amounts well in
excess of what IPC can use have requested (and in many
cases received) Iong-term contracts at fixed prices
strongly indicates that IPC's avoided cost rates are too
high and need reforming. I understand further that the QEs
primarily have been wind farms and that most of them have
availed themselves of SAR-based standard contracts, which
indicates that the standard contract price in particular is
too high. I agree with IPC's conclusi-on that reform is
required urgently.
2.I support the proposed use of the "IRP
method, " essentially the use of a system simulation, to
determine the energy price component for aII QF contracts.
I note that IPC proposes to base technology-specific
standard offers on IRP analysis of generic units of each of
the major anticipated types of QFs. I strongly agree with
this approach
3. The ceiling size of QEs eligible for
standard offers that was reduced recently from 1-0 average
megawatts ("aMW") (approximately 30 megawatts (*MW")
nameplate rating for wind) to l-00 kllrl for wind and solar
should remain 1ow, as IPC proposes. It also should be
reduced for other tlpes of QFs, notably hydro, because
HIERONYMUS, DI 13
Idaho Power Company
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hydroelectric projects are least amenable to generic
surrogates. If the lPC proposal to use separate generic
standard offers for the different technologies is
implemented, it could be approprlate to increase the
ceiling somewhat from the current 100 kW if it is found
that transaction costs of individualized rate negotiations
for small projects are too onerous.
t. Regarding the capacity element of
avoided cost, I support IPC's proposal to switch from a
combined cycle to a simple cycle peaking unit. As I shall
explaj-n later 1n my testimony, both theory and nearly
universal practice in the Regional Transmission
Organization ("RTO") markets that have capacity products is
to base capacity values on the net capacity cost of a
peaker.
5. Regarding the energy component of
avoided cost, I concur with IPC that the "letter of the
law" of PURPA is that avoided costs are the costs that the
utility avoids from on-system production or power purchases
and does not extend to paying QEs the incremental revenues
that might be earned from selling the QF power or other
power displaced by the QF into interchange markets. PURPA
requirements aside, it is poor public policy for IPC to be
required to enter into long-term obligations to pay QFs the
expected market pri-ce for power it incrementally will have
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Idaho Power Company
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to sell off system. I recognize that there may be
circumstances when IPC can seII QE power in interchange
markets for more than they wiII pay the QF under IPC's
proposal. A developer who believes it will be under-paid
as a QF can either develop a project elsewhere or build it
in Idaho but not request a QF contract, instead selling
into the commercial market. A further alternative is to
seIl it to IPC under its existing non-firm QF contract that
pays the project the net-back price of power delivered at
mid-Co1umbia.
6. I also support IPC's proposal to reduce
the required length of QE contracts. Even if it were
deemed appropriate to make projects "bankable" there is no
reason to extend contracts beyond L0 years. Moreover,
there is no reason why Idaho utilities' customers should
take on risks that properly belong to the 0F developers.
fn my opi-ni-on, IPC is if anything being overly generous in
terms of the length of contract that it is proposing. The
contract term it is offering is longer than is available in
exempt markets and exceeds the length of time that fdaho
utilities can hedge contract obligations to buy power that
must be disposed of in interchange markets. The need for
shortened contracts also relates to the market risks that
customers are being required to take on. If, as IPC
proposes, customers are largely insulated from risks
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relating to on-selling QF power into interchange markets,
contract length is somewhat less sensitive.
7. The fdaho utilities currently
differentiate between fueled and non-fueled QFs $rith the
former receiving priees that change year-by-year based on
actual gas prices rather than prices that were forecast at
the time of signing. Such an arrangement benefits both QF
developers and the utilities' customers since it reasonably
hedges the prices paid by the utilities and locks j-n
margins above fuel costs for the developers. This contract
form should be continued, as I understand IPC intends. The
benefits to customers from this form of contract are not
different merely because the QF is non-fueled. 9{hile IPC
is not proposing to extend this type of contract to non-
fueled QFs, f have reconrmended earlier in this testimony
that the Commission serj-ously consider this or other
changes to the form of non-fueled QF contracts to reduce
the risks borne by customers.
8. IPC is not proposing a market
alternative to administratively set avoided costs. Given
its excess energy situation, using an RFP to procure least
cost QF and other capacity does not seem to be a current
option, since the appropriate quantity j-n such an auction
would be zero. The other market option, passing market
prices from nearby visible competitive markets through to
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QEs in lieu of paying administratively determined avoided
cost rates, may or may not be consistent wj-th PURPA
depending on specific facts concerning market access that
have not examined. I nevertheless recommend to the Idaho
Commission that it examine the possible use of market
mechanj-sms as an alternative to administratively set
avoided costs now or at such later time as the facts
warrant -
III. PI'RPA PI'RPOSES IDID EISTORI
0. What is the origin of the requirement to
purchase power from QFs?
A.The requirement originates in PURPA. PURPA
was one of the energy polj-cy acts passed in the latter half
of the 1970s to implement the energy efficiency and
domestic energy supply goals of the Carter administration's
Project Independence. In response to the oil embargos that
disrupted oil supplies to the U.S. and caused both
shortages and several-foId increases in prices, the
government promulgated policies designed to reduce (with
the goal of total el-imination) dependence on imported oil.
These policies included increasing domestic oi1 and gas
production, promoting the use of renewable and other
domestj-cally produced energy, more efficient energy
conversion (e.9., in producing electrj-city), and more
efficient consumption of energy, among other things.
HTERONYMUS, DI L7
Idaho Power Company
1 Section 2L0 of PURPA is a relatively brief portion
2 of the bill that mandated arrangements under which electric
3 utilities would seII electricj-ty to, and buy electricity
4 from, qualifying cogeneration and small power production
5 facilities. Section 210 tasked FERC to devise rules that
6 "it determines necessary to encourage cogeneration and
7 small power production and to encourage geothermal
8 facilities of not more than 80 megawatts capacity. "l
9 Q. What guidance does the Act give FERC
l-0 concerning its implementation regulations?
11 A. The guidance is brief and mostly non-specific.
12 There are a few statements, however, that constrain and
13 direct FERC's implementation.
L4 The portion of Section 2l-0 dealing with purchases
15 required rules that "shall include provisions respecting
16 minimum reliability of qualifying cogeneration facilities
77 and sma1I power production facilities (including
l-8 reliability of such facilities during emergencies). ."
L9 The porti-on dealing with rules concerning rates to be paid
20 to such facilities by electric utilities:
1 FERC's implementatj-on treated the cut-off for small power
facilities as a maximum of 80 MW. However, this misread the plain
language of the Act, a careful reading of which shows that Congressapplied the 80 MW cut off solely to geothermal. A later passage in
Section 210 dealing with exempting such facilities from being regulated
as public utilities made such exemption available to geothermal plants
of less than 80 MW and other small power facilities of less than 30 MW.
As a classic example of bootstrapping, FERC later acknowledged this,
but continued to apply an 80 MW l-imit on the qrounds that this always
had been its policy.
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shall insure that, in requlring anyelectric utility to offer to purchaseelectric energy from any qualifying
cogeneration facility or qualifying small
power production facility, the rates for
such purchase:
ShaII be just and reasonable tothe electric consumers of theelectric utility and in the public
interest, and
Shal1 not discriminate againstqualifying cogenerators orqualifying smal1 power producers.
No such rule prescribed under subsection(a) of this section shal1 provide for arate which exceeds the incremental costto the electric utility of alternativeelectric energy.
The "incremental cost of alternative electrlc
24 energy" was subsequently defined:
Eor purposes of this section, the term
"incremental cost of alternative el-ectricenergy" means, with respect to electricenergy purchased from a qualifying
cogenerator or qualifying sma11 powerproducer, the cost to the electricutitity of the el-ectric energy which, but
for the purchase from such cogenerator or
small power producer, such utility would
produce or purchase from another source.
O. Did the Act show Congressional intent to
subsidize QEs?
A. No. ft cannot be over-emphasized that the
intent of PURPA Section 210 was to eliminate discrimination
agaJ-nst QFs, not to subsidize them. PURPA also was
intended to shield QEs from being regulated like public
HTERONYMUS, Dr 19
Idaho Power Company
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utilities. This shielding was percelved to eliminate cost
of service ratemaking as a fu11 or partial basis for
pricing QF power. This eliminated the customary method for
assuring that prices paid were just and reasonable. To
avoid subsidization of QFs by utility ratepayers, the upper
limit on payments to QFs was set at the costs that the
utility would avoid as a result of receiving power from the
QFs. In implementing Section 210, FERC concluded that
avoided cost shoul-d be not only the ceiling but also the
floor for avoided cost computation.
O. What pricj-ng terms are available to QFs under
Section 2L0?
A. The Act contemplates two classes of pricing
terms. First, the utility could pay the QE its avoided
cost as actually avoided at the time that the QF delivered
power. This was the only pricing method availabl-e for QFs
selling "as available" non-firm power. The Act also
contemplates the possibility of contracts that fix prices
or pricing formulae at the time of signing as an
alternative to the payment of actual avoided costs at the
tj-me of power delivery. Congress expressly found that
dj-vergence between contractual prices and actual avoided
costs would not in and of itself violate the Act. It is
unclear whether, as a matter of law (as distinct from EERC
or state regulatory implementation) that the option to set
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prices at the time that the contract was signed had to be
offered. However, if it was, the QE had the unilateral
right to select between this form of contract and being
paid avoided costs calculated at the time of delivery.
0.Does the Act require tariff-like standard
avoided cost rates for purchase contracts?
A.Yes, but only for very sma1l projects. The
utility is required to have a standard rate for sellers of
less than 100 kW and may, but need not, have a standard
rate for larger projects. These standard rates are
expressly permitted to vary by type of projects.
a.Slhat do EERC's implementing regulations say
about these types of contractual arrangements?
A.The pertinent part of the regulations
( (5294.304 (c) (3) (d) ) distinguishes between as avaj-1able
power sales and sales pursuant to a term contract. In the
former case, prices are avoided cost at the time of
delivery. In the latter case, they can be set at the time
of contracting. EERC recognizes expressly that such rates
may differ, even substantially, from actual avoided costs
at the time of delivery. FERC gives the QF developer the
unilateral right to select between the two contract forms.
However, the regulations do not expressly require that the
utility offer a long-term contract with fixed prices at
all, so this unilateral right is contingent on the
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1 alternative being offered.2 AI1 of this paraltels the
2 requirements of the Act.
3 What is not clear (and I pretend no legal analysis
4 of the points) is whether a contract for non-dispatchable,
5 intermittent energy such as wind is "as available" and
6 hence is only entitled to a rate determined at the time of
7 delivery.3 Assuming that such a QF is not deemed "as
B available" and hence is entitled to a rate determined at
9 the time of contracting, it is similarly unclear whether
10 this can be a formula rate (e.g., one that is indexed to
L1 vary wi-th, for example, gas prices or infLation) or if the
12 utility must offer a fixed schedule of rates for the term
13 of the contract. Relevant to this point, nothing in PURPA
t4 or the regulations specifies a required length of
15 contracts. Hence, even if the QF is deemed eligible for a
16 fixed rate for the term of the contract, the uti-lity can
1"7 offer only a relatively short-term contract.
18 O. Does FERC a1low non-conforming contracts?
19 A. Yes. FERC gives very wide latitude to QFs and
20 utilities to agree to whatever form of contract is mutually
2L acceptable. It expressly permits such contracts to yield
2 fn RM88-06 (1988), FERC cl-arified that the prices offered atsigning could be formula rates, not fixed prices.
3 The specific language in the regulations distinguishes betweenas-avai.l-able power and power from QFs able "to provide energy orcapacity pursuant to a legally enforceable obligation for the deliveryof energy or capacity over a specified term."
HTERONYMUS, Dr 22
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L rates that are below ful-I avoided cost, reasoning that the
2 QE might agree to a lower price in return for some valuable
3 non-price contract provision to which it_ was not expressly
4 entitled under PURPA. Conversely, such negotiated contacts
5 cannot l-awfully result in prices that exceed the utility's
6 avoided costs as calculated or incurred, whichever is
7 pertinent. Thus, while PURPA and FERC's implementation of
I it speak of encouraging cogeneration and sma11 poroer, such
9 encouragement is limited by a no subsidy provision that
10 does not al1ow rates to be set at a leve1 higher than the
1l- utilities' incremental cost since such a rate would not be
12 just and reasonable to consumers.
13 O. Did FERC's 1980 PURPA implementation give
L4 further guidance to the states in formulating more specific
15 implementation of Section 210?
l-6 A. Yes. The regulations specified data that the
I7 utility must provide to its state regulator (s) and directed
18 that this data should be taken into account in determining
19 avoided costs The regulations further said that rates
20 should be consj-stent with this data. 18 C.F.R S 292.304(e)
2L states that in setting avoided costs, "the following
22 factors shal1, to the extent practicable, be taken into
23account:..."
24
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2.The availability of capacity or
energy from a qualifying facility
during the system daily and
seasonal peak periods, including:
i. The ability of the utility todispatch the qualifyingfacility;
ii. The expected or demonstratedreliability of the qualifyingfacility;
iii. The terms of any contract orother legally enforceableobligation, including the
durat j-on of the obligation,
terminati-on notice
reguirement and sanctions for
non-compliance;
iv. The extent to which scheduledoutages of the qualifyingfacility can be usefullycoordinated with scheduledoutages of the utility'sfacilities;
v. The usefulness of energy andcapacity supplied from aqualifying facility during
system emergencies, includingits ability to separate itsload from its generation;
vi. The individual and aggregatevalue of energy and capacityfrom qualifying facilities on
the electric utility's
capacity
system; and
increments and the shorterlead times available with
additions of capacity from
qualifying facilities; and
vii. The smaller
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3. The relationship of theavailability of energy or capacityfrom the qualifying facility asderived in [the methodology basedon i through viil to the ability
of the el-ectric utility to avoidcosts, including the deferral of
capacity additions and the
reductlon of fossil fuel use; and
The costs or savings resultingfrom variations in line losses
from those that would have existedin the absence of purchases from aqualifying facility,if the
utilitypurchasingelectric
generated an equivalent amount of
energy itself or purchased an
equivalent amount of electric
energy or capacity.
A. Did state implementations of Section 210 occur
soon after FERC issued its regulations in Eebruary 1980?
A. No. Most states were somewhat slow to provide
25 the detailed rules needed to implement Section 210. This
was in part due to litigation concerning the FERC
regulations, focused primarily on EERC' s interpretation
that PURPA required payment of fu11 avoided cost rather
than some form of benefit sharing for new QEs. Ultimately,
in l-982, the U.S. Supreme Court ruled that FERC's actions
were within its discretionary authority. While some states
had moved quickly, others only began the process of
implementation at this time.
State implementation of PURPA occurred primarily
between L982, when litigation concerning FERC's
HTERONYMUS, Dr 25
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35
1 implementatj-on was resolved, and the mid-1980s. This was
2 an era when many state commissions were distrustful of
3 utilities' resource decisions as a result of overbuilding
4 and cost overruns for plants coming on-line during the
5 period. Some such commissions welcomed QEs in preference
6 to continued reliance on utilities building and owning all
7 new facilities.
8 Q. Recognizing that you plan to discuss how
9 PURPA has been implemented in some detail later in your
10 testimony, can you provide an overview of this initial
11 implementation?
L2 A. In all cases, state implementation was based
l-3 on administratively determlned costs. By administratively
L4 determined I mean that costs were determined by
15 methodologies or formulae determined or approved by
L6 regulators or legislative action rather than by observation
77 of market outcomes.a In the early 1980s there were no
18 competitive power markets with visibl-e prices. Almost
19 universally, utilities were vertically integrated and built
2A their own generation, so that there was litt1e opportunity
2l to observe long-term market prices. There were no
22 independent power producers as that term came to be used in
4 Short-term contracts for as available power are an exceptj-on tothis generalization since such power was, per requirement of the Act,paid the utilities actual avoided cost at Ehe tlme of delivery. Eventhj-s actual price was determined by methods created through regulationsince there was little if any price transparency.
HTERONYMUS, Dr 26
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1 the L990s. Hence, state implementation of PURPA inherently
2 involved study-based, rather than market-based, estimates
3 of avoided costs.
4 The state-by-state implementation resulted in a wide
5 range of administrative avoided cost calculation methods,
6 as I shall discuss later. Several of them certainly did
7 not take into account the factors that FERC had said should
8 be taken into account to the extent practicable and may
9 even have been facially inconsistent with the avoj-ded cost
10 definition contained in the statute and adopted in the
1l- regulations.
L2 O. Can you overvi-ew the main varieties of avoided
13 costs methods that the states adopted?
1-4 A. Several methods were adopted, for which the
15 two main archetypes rrrere a proxy unit, whose capacity and
L6 energy costs were used to define avoided costs, and the IRP
L7 or Differential Cost method, which measured avoided costs
l8 as the costs avoided as a result of contracting with the
l-9 specific QE in question. In addition, as a matter of law,
20 each state had a posted schedule of prices available to
2t units of no more than 1-00 kW, a limit extended higher and
22 even eliminated in some states.
23 Of the two methodologies, only the IRP method was
24 fully consistent with the definltion of avoided costs
25 contained in the Act. However, this distinction did not
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appear to be important at the time and, in the minds of
many, did not warrant the additional complexity and
transactions cost of the IRP method.
. 0. Why did the methodologies appear to yield
similar results?
A.At the time of initial state implementation,
the differences between the two types of methodologies were
not inherently large due to the nature of the QFs. Most
QEs were cogeneration units based on standard fossil power
plant designs, geothermal power, biomass (particularly wood
waste in timbering areas) and municj-pal solid waste. AI1
of these technologies had performance characteristics that
were reasonably similar to the conventional utility plants
used as proxy units. UIhiIe some wind unj-ts were built in
the 1980s, the technology of the day did not extend to
Iarge turbines or wind farms.s
0. Was PURPA as implemented successful?
A.It certainly was successful in causing large
amounts of QF capacity to be built. However, as noted
previously, creating QFs was not the intent of the Act.
Rather, the intent was merely to eliminate discrimination
against them as a barrier to their construction.
s fhe notable exception to this generalization was California.
Many thousands of sma1l wind turbines were built in three wind farmareas, at least partly as a result of non-PURPA state subsidies.
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The most obvious negative impact of PURPA was that
j-n some states contract rates significantly exceeded the
actual avoided costs when the power was delivered. This
arose in part because some state implementations required
utilities to offer avoided cost contracts of long duration
that al-so were sometimes front-loaded. These contracts
also contained pre-set prices. Since the Act and FERC
regulations provided no evident basj-s for limiting the
amount of 0F power the utilities were required to buy,
these contracts were not, 1n at least some states, Iimited
to the amount of power the utilities needed.5
A primary reason why prices were far above avoided
costs was that fossil fuel prices, especially the price of
natural gas, fell substantially soon after most state
implementations. Gas was the primary fuel used by
cogenerators. Hence, a contract rate based on a high gas
price forecast not only exceeded avoided cost, it also
substantially exceeded the cogenerators' costs. The
combination of a too-high rate, Iong contract durations and
no quantity limits, led to unexpected amounts of QF
development, primarily in the states with such long-term
fixed offers. In all likelihood, the "go1d rush" rapidity
6 QF development was very unevenreasons that some regions had little QEmid-1080s was a period of substantialcountry. This sometimes was reflectedcost rates.
across the country. One of theactivity was that the early to
excess capacity in much of the
in lower, "energy-on1y" avoided
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of entry was compounded by the fear on the part of
developers that a too-good deal would not long persist.
O. Can you provide examples of the extent to
which these hiqh prices created a glut of high priced QF
capacity?
A.The two leading examples of the adverse
consequences of long-term fixed price offers without
quantity limits were California and New York. California
established Standard Offers 2 and 4 (September 1983) that
provided for fixed avoided cost rates, no limit to the size
of the unit built (FERC had requlred Standard Offers for
any unit below 100 kW) and allowed the QF to opt for
levelization of palrments. The offers were suspended in
April 1985 when it became apparent that there was neither a
need for the quantity of capacity (16,000 MW under contract
or in the contracting process in the mid-l-980s) nor the
excess cost for the energy, estimated by Southern
California Edison and Pacific Gas & Electric, the two
largest utilities, to be $1.15 bil1ion per year by L990.?
Earlier the New York state Iegislature had passed a
law requiring that the state's utilities enter into long-
term contracts with QFs. The New York Public Service
' See Frank Graves et aI, PURPA: I'laking the Seguel better Than theOriginal, (prepared for The Edison Electric Institute), The Brattle
Group (December 2005) on-1ine at:
http: / /wuw . eei . orglwhatwedo/PublicPolicyAdvocacy/StateRegulation/Docume
nts,/purpa.pdf, at p. 16.
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Commission bras to set the rates but was constrained to set
them no lower than 6 cents per kWh, well above the then-
current avoided costs of utilities in New York.8
Thls was argued to be acceptable because it had
encouraged significant quantities of QFs into the state and
had had little impact on the consumer price of electricity.
New York utilities argued (unsuccessfully) that the 6 cent
number was weLl in excess of their avoi-ded cost with
Consol-idated Edison stating that in 1986 their avoided cost
was only 3 cents and Orange and Rockland arguing it was 3.4
cents. Orange and Rockland went further to state that they
did not anticipate their avoided cost to reach 6 cents
until 1995.e
The cost of excess QE power bought under the 6 cent
rule became manifest when New York restructured the
electrj-city industry, requiring generation divestiture and
retail access, among other things. Niagara Mohawk, a mid-
size utility, obtained regulatory permission to enter into
negotiations to terminate or modify its QE obligations in
order to quantify its excess costs that would become
I FERC later opined that New York may have relied on a statementthat it had made in the preamble to its regulat,ions to the effect thatstates could require rates above avoided costs, notwithstanding PURPA.
However, since such rates were facially inconsistent with the express
Ianguage of the statute, the legitimacy of such rates could not rely onPURPA. Nevertheless, New York treated the 6 cent program as PURPArelated, requiring that its utilities accept all QF power offered to
them and pay this rate.
e Ibid. at page 15.
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A.
stranded by the change in industry structure. It succeeded
in cancelting 14 of its 27 QF contracts at a cash cost of
$3.9 billion plus 23 percent of Niagara Mohawk equity.
o.Was dissatisfaction with the results of PURPA
implementation Iimited to these two states?
A.No. Other states also had considerable
excesses of PURPA power. Many such states either suspended
or diminished their PURPA offers. Others began to ratj-on
QEs, along with non-QE new capacity offers by creating
quantity-limited procurements, with the lowest, quality-
adjusted offers being accepted and al-1 others rejected.
Conversely, QF developers in some other states complained
that they were not being offered payments for capacity.
This dissatisfaction in both camps led to the next chapter
in the PURPA saga, the Congressional hearj-ngs of 1986 and
the FERC Notices of Proposed Rul-emaking ("NOPRs") of 1988.
rhe Rlt-88 NOPRs
What was the origin and subject of the NOPRs?
The substantial unhappiness with the results
of PURPA implementation 1ed to hearings in both houses of
Congress in June of L985. FERC responded by holding
regional conferences in the spring of 1,987 at which various
parties testified concerning changes in EERC's regulations
implementing Section 2L0 that would eliminate undesirable
parts of state implementations. After the hearings were
HIERONYMUS, Dr 32
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l- conducted, FERC issued three interrelated NOPRslo in the
2 spring of 1988. These concerned: (a) the treatment of
3 independent power producers, (b) the use of structured
4 procurements to, among other things, comply with PURPA (the
5 Bidding NOPR), and (c) changes in the existing PURPA
6 avoided cost regulations (the Avoided Cost NOPR). The
7 latter two are relevant to the j-ssues in this proceeding."
B Q. Were the regulations proposed in these NOPRs
9 adopted?
l-0 A. No. The NOPRs were very controversial- at the
11 time. The controversy was not primarily about the changes
12 they proposed in regulations concerning avoided cost
13 pricing, but in the way in which the NOPRs proposed to
L4 restructure the electricity industry. Much of what the
l-5 NOPRs proposed has since occurred. Fundamentally, the
16 NOPRs called for open transmission access, mandated but did
17 not require competitive bidding for contracts for all- new
l-8 generation including utility provided generation that would
L9 then not be subject to cost of service regulation, and
10 FERC uses NOPRs as a mechanism for eliciting comments from
interested parties concerning proposed changes in regulations.Usually, they contain a long discussion of the issue being addressed
and a draft of the proposed new regulations. While a NOPR is notitself a regulation, it generally contains substantial information
about how the Commissi.on would react to particular fact circumstances.
11 The Independent Power Producer NOPR proposed streamlining
regulation of a proposed new type of generators that would not be
subject to cost of service price regulation. This presaged thecreation of Exempt Wholesale Generators in the Energy Policy Act of
L992, b:ut has no direct relevance to the PURPA story.
HIERONYMUS, DI 33
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1 provisions to polj-ce self-dealing in utilities' selection
2 between affiliated and unaffiliated generation proposals.
3 Among those opposing the NOPRs were National
4 Association of Regulatory Utility Commissioners and one of
5 the FERC Commissloners, who wrote a scathing attack on the
6 Iegality of the proposed changes in regulatj-ons insofar as
7 their effect was to restructure the industry. The proposed
8 regulations \^rere quietly abandoned and FERC moved on to a
9 more gradual change in policy, beginning with Order 888 on
l-0 open access in 1998 and with the further changes authorized
11 or enabled by the Energy Policy Acts of 1992 and 2005.
L2 O. If the NOPRs did not change FERC's
13 regulations, why are they worth discussing?
L4 A. Notwithstanding the fate of the NOPRs, they
15 provide a useful sunmary of problems that arose in the
16 j-mplementation of PURPA and important information about
77 FERC's interpretation of its own regulations that, in
18 relevant part, are little changed today.
19 lIhe Avoided Coct ![OgR, Rt{88-6
20 O. Did the NOPR recount comments received and
2L lessons learned in the Congressional hearings and its own
22 regional conferences?
23 A. Yes. The NOPR recounts the types of
24 dissatisfaction with the way that states had implemented
25 the avoided cost standard in Section 210. Overall, EERC
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characterized the comments as calling for moderate changes
and being focused primarily on the treatment of capacity.
EERC' s description of criticisms of the implementation of
the portion of Sectj-on 21-0 regarding QF purchases by
utilities were organized into the following topj-cs:
1. Inappropriate Methods for Dqtermining
Avoided Costs.
a. Quantitative Limits on Capacity
Needs. EERC characterized this as the most common
complaint. The 1980s were a period of substantial excess
capacity in much of the U.S., but utilities nonetheless
were required to buy energy and capacity from QFs, often
based on avoided cost methods that assumed a need for
capacity. Conversely, QE developers complained that many
states' implementations gave no capacity credlts. The most
common specific complaint arose from a lack of quantity
Iimits in the requirement to sign contracts or in the
amount of QF capacity that would receive payments for
capacity.12 EERC pointed to standard offers, extended far
past the 100 kW statutory requirement as one source of this
problem, but commented that the "committed capacity"
12 As a l-ead example, FERC cited comments by Pennsylvania Powerand Light. Its state commission disallowed the entirety of its
Susquehanna 2 nuclear ptant from rate base as not used and useful
because it was excess to the company's capacity requirements but then
required the company to contract for 500 MW of QFs.
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approachl3 and other avoided cost methods also could lead to
unlimited capacity commitments.
b. Eailure to Take into Account
Qualj-tative Characteristics. In its l-980 regulations
implementing PURPA Section 210, FERC had listed several-
qualitative factors that must be considered but need not be
taken j-nto account j-n state implementations. Comments
criticized many of the methods used for not differentiating
between the characteristics of QFs and the plant used to
set avoided cost, using a proxy unit that is not consistent
with the utility's needs to set avoided costs, and not
differentiating among QEs in terms of characteristics such
as dispatchability.
c. Problems When QF Capacity Offered
Exceeds Utility Needs. Even reasonably calculated avoided
costs can elicit more capacity than is needed under some
clrcumstances. This especially is true if all capacity
receives capacity payments. FERC also noted that some
states that did ration capacity paylnents used methods that
may not be efficient, such as first come, first serve.
d. Wholesal-e Sources. Proxy unit
methods inherently
cost of power from
assume that avoided cost relates to the
the proxy unit, whereas for many
'3 The committed capacity method usedunit built by the utility or the costs ofbui1t by the utility as the proxy unit for
the costs of either the lastthe next unit proposed to becalculating avoided costs.
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utilities, the lowest cost alternative was purchases from
other utilities. Eurther, some commenters indicated that
their state commissions did not understand that avoided
purchases could ever qualify for use in avoided cost
calculations.
2.Fixed Price Contracts. Some commenters
complained that fixed price, must take QF contracts
prevented the utility from buying substantially cheaper
economy energy as an alternative. Others noted that at
times they had to back down low variable cost baseload
units to make room for more expensive QF power. Stil1
others asked for guidance concerning the use of fixed
prices in long term contracts.
3. Rates Exceeding Avoided Costs. FERC
noted that some states had interpreted part of FERC's
regulations as allowing states to set PURPA rates above
avoided costs. The New York 6 cent minimum price, which
the New York State Department of Pub1ic Service (*NYPSC")
Chair stated was above any of the state's utilities'
avoided cost, was said to be predicated on thi-s beLief.
EERC clarified that its intent when it earlier stated that
rates above avoided cost were permissible had been to point
out that, outside of PURPA, states could mandate purchases
at above avoided costs. PURPA rates, however, could not
exceed avoided cost.
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4. Multistate Utilities. Utilities that were
jurisdictional to more than one state complained that
different st.ate implementations led to different avoided
costs. This arose both from adoption of different
methodologies and from basing avoided costs on the avoided
costs of the subsidiary that provided service in that state
rather than on the system as a whole.
o.What are the major points made by FERC in the
avoided cost NOPR that you believe warrant emphasis?
A. In this NOPR, FERC clarified or emphasized
several matters that still bear on the setting of avoided
costs. One point made was that PURPA was not intended to
subsidize QEs, whatever their merits: "It shoul-d be
emphasized that the avoided cost standard dictates that QFs
should be paid consistent with, not their social value, but
the costs of displaced sources of power to utilities. The
criteria for qualification as a QF must carry the burden of
assurj.ng that the QF's mode of generation is socially
desirable. [p.30] "
The Commission also stated that problems were
arising from avoided cost methodologies that imputed value
to the QF that, in fact, were phantom:
Inaccurate calculations of avoidedcapacity cost appear to result in partfrom a lack of attention to therelationship between the characteristicsof the QFs involved and the quality,
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quantity, or source of the capacityavoided. For utilities to use QF powerinstead of building new plants orpurchasing power, it is necessary for thequalitative characteristj-cs of QPs andutilities' plans to at ]east roughlycoincide. tp.35l
Several portions of the NOPR emphasize that the
capacity palrments to be made to a QF depend critically on
whether the existence of the QF a1lows capacity to be
avoided. Eor example, "Under the Commission's current
regulations, capacity payments need to be made when, and
only when the purchase or construction of capacity will be
avoided by the purchasing electric utility as a result of
its purchase of QE power tp. 61." Sti1l more emphatically:
Section 292.2A4 (c) of the current
regulations has been read as allowing
open-ended standard offers to al-f QFs.It is cIear, however, that the avoidedcost standard requires that QFs be paid
for only the capacity cost that a utility
avoids because of the presence of QEsTo address this problem, the
Commission proposes to amend its
regulations to assure that Iunder] suchstandard offers . capacity paymentswould not be available once the
purchasing utility's capacity needs have
been satisfied. tp. 4Bl.
FERC al-so considered the issue of the availability
of standard rates as opposed to QF-specific calculations of
avoided cost. It stated that, based on experience, it
proposed to raise the threshold from the statutory 100 kW
to a project size of 1 MW.
HTERONYMUS, DI 39
fdaho Power Company
1- In a section entitled "avoided energy costsr " FERC
2 endorsed time-based differentiation of avoided energy
3 payments, recognizing that energy costs differ by season
4 and time of day.
5 Q. Did the Avoided Cost NOPR discuss the problem
6 of long-term contracts with fixed prices?
7 A. Yes. An entire section of the Order (pp. 55-
8 67 ) dealt wlth problems arising from fixed price contacts.
9 It noted that QF revenue certainty rendered via contract
10 provisions shifted risks from the QF to the purchasing
L1 utility or its ratepayers. It also noted that fixed rates
L2 could reduce transaction costs, which coul-d be important
13 for smaI1 Qfs. It made cl-ear that its use of the term
t4 "fixed price" incorporated a variety of rate types for
1-5 which the only conrmon feature was that they were set based
16 on provisions contained in the contract:
t1 For purposes of this proposed rule, the18 term "fixed-Price contract" refers to any19 lega11y enforceable obligation wherein20 the rates for purchases by a utility are2t established in advance of the time of22 purchase. The fixed price may be a23 si-ng1e, uniform rate per kilowatt or24 kilowatt-hour for all po$rer, includi-ng a25 fixed formula rate, or a complex schedule26 of time-differenti-ated rates and other27 payments. The contract's term may range28 from decades to months. tp.56l
2930 Erom this description, and in particular the
31 inclusion of formula rates, it is reasonable to interpret
HIERONYMUS, DI 40
Idaho Power Company
1 that the Commission was of the view that the right of a QF
2 unilaterally to select a contract based on avoided costs
3 determined at the time of the contract did not extend to
4 the right to insist on a predetermined schedule of prices
5 for the duration of the contract.
6 The Commission noted that inefficiencies arose
7 whenever rates deviated from avoided costs, since the
8 utility would be paying too much or too littIe. Further,
9 when it was paying too much, this could mean that QE power
L0 was bej-ng purchased and produced in lieu of lower cost,
11 more efficient power. It noted in particular the rigidity
1,2 arising from non-dispatchability:
13 Most of the problems with efficiency14 associated with Iong term fixed-price1"5 contracts flow from the rigidities suchl-6 contracts impose on price and quantity ofl7 electricity. These problems can beL8 ameliorated by relaxing restriction onl-9 price or quantityr or by shortening the20 contract period. Quantity flexibility2L implies QF dispatchability. rf the22 utitity is unable to "turn the QF off" it23 may be unable to take advantage of24 economy energy, or it may have to back25 down its more efficient plants to buy26 higher priced QF energy. If the utility27 cannot "turn the QE on" it may not be28 able to take advantage of the QF's29 capacity when it is most needed during30 peak demand or a system emergency.31- tpp. 61-52l
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33 The Commission proposes to amend its34 regulations in order to allow for greater35 pricing flexibility. Pricing flexibility35 may take several different forms. For
HIERONYMUS, DI 4t
Idaho Power Company
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j-nstance a contract could provide QFswith a price floor applj-cab1e to a1l the
povrer supplied to the utility, but stil1provide for higher variable unit prices
reflecting daily or seasonal periods.
The price floor would provide the revenue
stream necessary for the QE to secure
financial support while the price
variability would induce the QF to
maxj-mize deliveries in peak-1oad periodswhen the utility values additionalsupplies most. Of course, the pricefloor should not exceed the minimum valueof the utility's avoided cost.Similarly, a contract could provide for atwo part price a fixed payment forcapacity and an energy price for power
delivered. The QE would be assured a
minimum revenue stream based on the value
of its capacity. The variable energy
component would allow the utility to
dispatch the QE capacity only when it was
economr_c.Ialhatever the pattern ofcontract payments, rates for purchases
from QFs should always reflect how wellthe characteristics of the supplier's
:":":
match the purchasing utility's need
To avoid problems such as those
associated with take-or-pay contacts inthe natural- gas industry, la the
Commission wishes to stress the danger ofincluding forecasted fuel costs in thefixed rate structure of long-termcontracts, especially in combination withthe specification of minimum purchasesquantities.Ihe Commission also
encourages the use of time-of-day and
14 Following partial decontrol of wellhead natural gas prices,
uncontrolled incremental prices escalated rapidly. Many natural gas
utilities signed take or pay contracts at very high prices. When
decontrol became complete, eliminating 1ow prices for non-incrementalgas and expanded supply created a glut of gdsr prices fel1 verysubstantially. This created a regulatory problem: either contractcosts far in excess of actual costs would have to be passed through inrates or the excess costs would be "trapped" in the utility, leading in
some cases to bankruptcy.
HIERONYMUS, DI 42
fdaho Power Company
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in flexible pricing
Iong-term contracts.
O. Did the Commission express surprise at the
extent of the problems identified concerning the scale of
QE power brought about by long term contracts at fixed
prices?
A.Yes. Elsewhere in the NOPR, the Commission
commented that the risk that QFs would offer more capacity
than the utility could use had not been anticipated at the
time its regulations were written, but had become manifest
as a resul-t of the rapid growth in QF po$rer. It noted that
in its l-980 Order it had forecasted 2,636 MW of QF power by
1985, whereas the amount actually installed (i.e., not
including contracts requested or contracts slgned with
facilities not yet in production) was 12,L20 ltM.
o.Did FERC also address revenue shaping for Iong
term contracts?
A.Yes. One issue concerning long-term contracts
discussed by the Commission was the front-end loadj-ng of
revenues. The Commission expressed concerns about
intergenerational equity arising from front-end loading.
It also voiced a concern that, having received above market
prices in the early years, the supplier would walk away
from its contractual responsibility which could turn out to
be delivering power at a loss in the later years.
HTERONYMUS, Dr 43
Idaho Power Company
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o.Did the Commission provide advice to states
concerning how to avoid attracting unneeded capacity?
A. Yes. The Commlssion acknowledged the
difficulty of administratively setting avoided cost rates
at the proper level, such that mistakes were not always
avoidable. It suggested that states should monitor whether
their avoided cost rates hrere attracting unneeded QFs and,
if so, consider lowering them. Intriguingly, despite
language in PURPA and in the Commission's regulations that
seemed to require utilities to buy power from QFs in the
amounts offered, it suggested that a state that had set
rates that attracted too much power could suspend the rate
pending its recalculation:1s
If, in response to such a standard rate
or standard offer, QFs offer much morecapacity than the utility needs, aprospective adjustment to the rate should
be considered for contracts that have notyet been entered into. If the excess
amount of offered capacity is large, thenthe state regulatory authority or non-regulated electric utitity may want tore-examine its method for determiningavoided capacity costs to see if someefficient alternatives available to theutility were not considered.The
Commission belj-eves that if QFs offer
capacity in amounts greatly exceeding theutility's capacity needs, then the ratefor purchase of that capacj-ty was
probably not set in reference to the costof the utility's most efficient
15As rprecisely what
QF offers.
noted earlier, thisCalifornia had done
suspension of a standard offer isto choke off its massive surplus of
HIERONYMUS, DI 44
Idaho Power Company
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alternative.A rate that does notreflect the cost of the utility's mostefficient alternative source of capacityis excessJ-ve, and should be adjusted
downward. .
Moreover, even a properly calculatedstandard offer will notappropriate indefinitely.rema].n
The
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the Avolded Cost NOPR would fix the identified problems?
No. Frustration with the difficulty of
getting administratively determj-ned avoided costs to
achieve the purposes of PURPA Section 210 led the
Commission to propose bidding as an alternative to
administratively set offers:
A.
alternative upon which a rate is figured
comprises a certain block of capacity.If this block is fu1ly satisfied, a
change in the standard offer may be
necessary.
The Commission recognizes the difficultyof administratively setting avoided costrates that induce QFs to supply capacityin amounts that exactly match a utility's
needs.Obviously, the signing of
contracts with QFs cannot and shoul-d notbe postponed until a rate has been setthat successfully matches the amount of
QF power with the capacity needed by the
purchasing utility. . Rather, in the
event that it becomes clear that a rateis eliciting more QF power than theutility needs, the state regulatoryauthorj-ties or non-regulated electricutility could suspend the rate. tpp. 4L-
42 .1
Did the Commission express optimism that the
was proposing and the advice it was giving in
HTERONYMUS, Dr 45
Idaho Power Company
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Admittedly, administratively calculated
avoided cost is unlikely to successfully
result in an equilibrium price. The
Commission believes that bidding is analternative that promises efficiency in
both determining avoided cost rates and
assigning avoided cost payments among
QFs.
The thinking behind the Commission's espousal of
bidding, and in particular the use of biddinq as a way to
evade the apparent inability to refuse QF power, j-s buried
in a long footnote in the Avoided Cost NOPR:
The Commission has tentatively concludedthat purchases from other QFs faI1 within
the meaning of "another source" under the
section 210 (d) definition of "incrementalcost of alternative energy. . . ." If autility does not purchase from oneparticular QF, it certainly has the
option of purchasing power from other QFsObviously, if a utility
purchases power from a QF at a price thatis higher than a rate for comparablepower available from another source,
whether it is another utility or another
QF, the purchasing utilj-ty's customerrates would be higher than they would
have been had the purchase not been made
and the purchasing utility had purchased
from that other source. tpp. 35-361 ,
lhe Bi&liag !|OPR, Rl{88-05
What was the purpose of the bidding NOPR?
The bidding NOPR proposed draft rules for
using bidding to set utilities' avoided costs for use in
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purchasing from QFs.
NOPR:
As stated in the introduction to the
HIERONYMUS, DI 46
Idaho Power Company
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The Federal Energy Regulatory Commj-ssion
(Commission) proposed to adopt regulationsthat would authorize state regulatoryauthorities and nonregulated electricutilj-ties to implement bidding procedures
as a means of establishing rates for power
purchases from qualifying facilities (QFs)
under section 2L0 of the Public Utility
Regulatory Policies Act of 1978 (PURPA). Abidding program is a formally organized
market to acquire incremental supplies ofelectricity.This proposed rulesanctions the use of bidding as a
procedure for purchasing electricity for
purchasing electricity from QEs.
The Commission determined that bidding could
eliminate errors and controversy in administratively1B
l_9 determined avoided costs.In particularly, it noted that
20 some state regulators ignored whole classes of
alternatives, relying on a single proxy unit that may not
be the utility's lowest cost alternative which,
23 particularly in times of overcapacity, often is a purchase.
The Commissi-on noted that states and utilities were
only just beginning to experiment with biddingl6 and that it
was therefore reluctant to be too proscriptive about how
27 procurements shoul-d be organized. States were free to
adopt bidding for some, all, or none of the utilities'
requirements. Moreover, while FERC uses the term "bidding"
30 to refer to the procurement methods covered by this NOPR,
LG It states (page 15) that Maine,
had promulgated bidding rules and thatprocurement. Bidding was said to be
consideratj-on in 14 other states, one of
Massachusetts, and California
Texas had a related form ofunder development or at least
which was Idaho.
HTERONYMUS, Dr 47
fdaho Power Company
1 it stated that a wide variety of approaches woul-d qualify
2 as bidding.
3 Q. What benefits were seen to arise from using
4 bidding as a method of determining avoided costs?
5 A. While using price discovery in market
6 procurements to set avoj-ded cost was one goal of the
7 Commission's bidding proposal, it was not the only and
8 perhaps not even the main reason for advocating it. The
9 Commission stated fIat1y that "the purpose of bidding is to
l-0 determine which suppliers will receive avoided capacity
11- payments." Implicit in that statement is the presumption
L2 that a state that adopted bidding would procure all of the
13 utilities' capacity needs through the bidding process,
L4 notwithstanding its statements elsewhere that bidding could
l-5 be used to meet only part of the requirements. Non-QF
16 projects that were not selected, including projects
l7 sponsored by the utilities themselves, would have no right
18 to any revenues and presumably would not receive siting
19 approval.
20 O. Did adopting bidding mean that states could
2l avoid the utilities' open-ended obligation to buy QE power
22 at their avoided costs?
23 A. No. The Commission recognized that PURPA
24 Section 210 did not limit the requirement to buy QF power
25 to the amount that the utility needed for reliability
HIERONYMUS, DI 48
Idaho Power Company
1 purposes. However, it reasoned that the PURPA's "must buy"
2 requirement did not extend to paying capacity palments to
3 QFs that were unneeded and not selected as being economic
4 in the bidding procedure. Hence, while the utility sti11
5 would have to pay an administratively determined energy
6 payment to QFs that did not have accepted bids, the QFs
7 would not be entitled to capacity payments.
8 Left unsaid was the expectation that few QFs would
9 be built if they did not receive capacity payments. At the
10 time of the NOPR, avoided energy would typically be from
11 coal or gas-fired capacity (owned or purchased) and priced
L2 at relatively low marginal costs. This would be true all
L3 of the time if the adminj-stratively determi-ned energy price
L4 for QFs not selected in response to the RFP was based on a
15 proxy unit, and much of the time even if IRP-type methods
L6 were used. Hence, most QFs would earn quite Iittle from
L1 these avoided energy-only palrments. By limiting the amount
18 of capacity/energy production capability purchased via
19 bidding to the amount that the utility needed and limiting
20 the right to earn avoided capacity cost to the winning
2L bidders, the inefficiency otherwise inherent in the
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HIERONYMUS, DI 49
Idaho Power Company
l- statutory obligation to purchase unlimited QF energy would
2 be f inessed. rT
3 Q. Did the Commission provide guidance about who
4 should be allowed to participate in bidding?
5 A. The Commission expressed a preference that
6 bidding would be "aIl source" bidding, with QF, Independent
7 Power Producer, and utility projects aII competing
8 simultaneously. It reasoned that only an all-source
9 procurement could ensure that the least cost capacity and
10 energy was being procured. Having stated this preference,
11 the Commission then proposed that a1I sources could be
L2 deemed to have been taken into account in a bidding
13 procurement even if they could not participate directly.
L4 One of several ideas that it floated was that a "benchmark"
l-5 avoided cost could be established based on the utility's
16 IRP and the procurement would then be for resources that
1-'7 would replace portions of it.
18 0. Was bidding proposed to select winners sole1y
19 on the basis of price?
20 A. No. The NOPR stated that non-price attrj-butes
2L could and should be taken into account in the "scoring"
1? 'PURPA imposes an absolute duty upon a utility to offer to
purchase electric energy from QFs at rates that do not exceed the rcost
to the electric utility of the electric energy which, but for thepurchase from such cogenerator or small power producer, such utility
would generate or purchase from another source. The Commission hasinterpreted electric energy to j-nclude capacity when capacity isavoided by the utiTity as a resuTt of its purchase'from the QF.'
tEmphasis added; p. 37.1
HIERONYMUS, DI 50
Idaho Power Company
L used to select winning bids. It left it to the states and
2 (where state regulators so-delegated) the utilities to
3 develop appropriate procedures.
4 Q. lrlas this proposal a radical change when viewed
5 from the prospective of 1988?
6 A. Yes, it was. The NOPR pre-dated the creatj-on
7 of the class of Exempt Wholesale Generators by four years
I and the earliest state-level restructuring of utilities by
9 about eight years. I noted earlier that the three NOPRs
L0 proposed by the Commission in March of 1988 were never
l-1 converted into regulations. The bidding NOPR is likely the
L2 primary reason for the fierceness of opposition. The
13 bidding NOPR proposed to replace cost of service regulation
L4 by market based prices established in auctions. This would
l-5 eliminate cost-based regulation of new (and ultimately all)
16 utility-owned generation that was primarily a province of
L'l state commissj-ons. The dissenting Commissioner charged
18 that the majorlty was seeking to unilaterally restructure
L9 the industry based on a "Genco,/Disco" model of utilitj-es,
20 where the GENCO was not price regulated, and competed wlth
2L similarly unregulated IPPs.
22 A. Notwithstanding that the NOPRs were not
23 adopted, were the concepts contained therein subsequently
24 put to use?
25
HIERONYMUS, D] 51
Idaho Power Company
1 A. Yes. While this NOPR may well have been a
2 "bridge too far" in 1988, many of the core concepts in it,
3 including those that were considered most radical, were
4 adopted subsequently. The "Genco/Disco" model of industry
5 structure was already under active discussion. The model
6 was implemented two years Later in the United Kingdom and
7 became the preferred template for aII of the European
8 Community under regulations enacted by the Community in the
9 early 1990s. The U.S. Energy Policy Act of L992 created
10 Exempt Wholesale Generators, independent power producers
11 allowed to compete to sell at wholesale to utilities
L2 without the cost of service and other utility regulations
13 to which they previously would have been subject.
L4 Several states adopted competitive bidding as the
15 primary means of procurement shortly after the NOPR.
16 Within a decade, the "Genco/Disco" model was adopted for
L7 more than half the load-serving utilities in the country.
18 The Eaergy Policy Acts of 1992 and 2005
19 O. You mentioned the Energy Policy Act of 1992-
20 What did that Act do that relates to your testimony?
2l A. The Act created a new class of generators,
22 called Exempt V'lholesale Generators ("EWGs") who, like QEs
23 were exempt from utility regulati-on but, unlike QFs, urere
24 not limited in size or fuel- type. AIso unlike QEs, they
25 had no right to "put" contracts to utilities. Many saw the
HIERONYMUS, DI 52
Idaho Power Company
1 evolution of privately sponsored generation as an
2 alternatj-ve to both QFs and a utility generation monopoly.
3 Soon after the Energy Policy Act of L992, a number
4 of states (including those that had created the greatest
5 surpluses of QE contracts) began to consider deregulation
6 of the generating sector including, j-n many cases, the
7 divestj-ture of util-ity owned generation (which then would
B become EWGs). As the l-990s progressed, the development of
9 regional transmission entities and power markets,
10 deregulation of generation pricing and investments, and
1-1 retail access progressed. While the California crisis of
'J.2 2000-2001 curtailed the spread of retail access and fuII
13 reliance on markets to provide needed generation, the
L4 restructuring of the industry already encompassed more than
1-5 half of the country.
1-6 O. In the period after the Energy Policy Act of
L7 1992, was there a decline in the amount of, and i-nterest in
1-8 QFs?
19 A. Yes. Generally, increasj-ng focus on
20 reorgani-zation of the electricity sector, the creation of
2L RTOs and retai-l- access put the avoided cost issue on the
22 back burner as a policy matter. The adoption of bidding
23 that included ElrtrGs along with QFs as a means of procuring
24 power and meeting PURPA obligations, lower fuel prices and
25 prlce forecasts and changes in avoided cost methodologies
HIERONYMUS, DI 53
Idaho Power Company
1 in some states made PURPA contracts less attractive for
2 developers. Indeed, the predomj-nant PURPA issue in the
3 1990s was how to unwind uneconomic QE contracts as part of
4 electricity seetor restructurJ-ng.
5 Q. What resulted from the Energy Policy Act of
6 200s?
7 A. The advent of retail access and creation of
B regional entities with non-discriminatory transmission
9 access eli.minated the basis for the anti-discrimination
10 purposes of PURPA in affected parts of the country.
l-1- Eurther, utilities that lacked retail monopolies no longer
L2 had the assurance that any excess PURPA-related costs could
13 be passed through to customers. After successive attempts
14 to eliminate PURPA Section 210 in 1ts entirety, proponents
15 convinced Congress to include amendments to PURPA in the
L6 Energy Policy Act of 2005 ("EPAct"). Of greatest
L7 relevance, a new Part M of PURPA exempted utilities in
18 designated RTOs)from the Section 210 purchase requirement
19 for all but small power plants. Utilities outside of these
20 RTOs were gi-ven the opportunity to demonstrate to EERC that
2L QEs connected to them had comparable competitive access and
22 to thereby gain exemption. If this demonstration was made,
23 FERC would be obligated to exempt the utility from the
24 purchase obligation.
25
HIERONYMUS, DI 54
Idaho Power Company
l- The consequence of exemption is that projects that
2 would have qualified as QFs no longer have a counterparty
3 who must buy from them. Since they have non-discriminatory
4 access to markets, in particul-ar the spot markets of the
5 RTOs, the original purposes of PURPA are deemed by Congress
6 to have been satisfied and, havlng found that such access
7 exists, FERC not only could but must eliminate the QF
B purchase requirement.
9 Q. Did EPAct cause a rethinking of avoided cost
l-0 methodologies?
1-1 A. To at least some degree. The passage of the
12 Energy Policy Act of 2005 and a requirement that EERC
13 implement changes in its regulations to reflect it18
L4 highliqhted the limited j-ntention of Section 210. While
15 EPAct only abolished the PURPA requlrement in the four
16 Eastern RTOs and in ERCOT, and created an opportunity for
L7 utilities in the Southwest Power Pool and in California to
1-8 become exempt, the criteria for exemption clarified that
L9 aII PUPRA required was a non-discriminatory opportunity for
20 QEs to receive market prices. Thls created a fresh
2L benchmark against which the avoided cost methods of other
18 There were only two changes relevant to Section 210, the onlypart of PURPA dealing with QEs. A new Part M allowed utilities in RTOswith certain characteristics to be exempt from entering into new or
renewed QF contracts and spelled out the circumstances under whichother utiliti-es could become exempt. The new Part N eliminated QFrights for what were usually referred to as 'PURPA machines, "cogeneration facil-ities for which the non-electric use was minor andoften contrived.
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Idaho Power Company
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utilities that remained subject to essentially unchanged
requirements to purchase QE power could be compared. le
Because EERC had not made major changes in its regulations
slnce 1980, some saw EPAct as a triggerlng event for
remedying elements of the FERC regulations that had been
shown to cause serious problems for the j-ndustry.
O. Please explain how EPAct clarified the core
requirements of a PURPA-compliant procurement methodology.
A. The EPAct provision that exempted utilities in
RTOs from PURPA is highly instructive of what Congress
considered to be the core reason for the PURPA requirement.
Essentially, what Congress concluded was that if a QF was
Located i-n an RTO or similar market, then it had access to
a competitive market and was thereby assured of non-
discriminatory prices. The competitive market that is the
sjne qua non of an RTO is a real time spot market. No RTO
requires any load serving entity to purchase energy
bilaterally on a long-term basis and the longest term for a
guaranteed capacity price in any RTO is three years.
The fact that membership in an RTO rAras a sufficient
basis for exemption therefore clarified which commonly
included el-ements of PUPRA implementation were not required
by the Iaw. There is no need for "bankable" long-term
1e As implemented by FERC, the newoutside of the RTOs to become exempt ifin their Balancing Authority Areas hadthat was at least as favorable as access
Part M allowed other utilities
they could demonstrate that QFsaccess to competitive marketsto RTO spot markets.
HTERONYMUS, Dr 56
Idaho Power Company
1 contracts or the shifting of price risk from the generator
2 to a utility. Capacity payments, which exist at all in
3 only some of the exempted markets, are not guaranteed for
4 any material length of time and are reduced substantially
5 whenever there is excess capacity. No exempt load serving
6 entity is required or expected to buy capacity or energy in
7 excess of its anticipated needs.
8 Q. You have been focusing on legislative and
9 regulatory events. Were there changes in electricity
10 markets in the l-ast decade that also impacted PUPRA
11 compliance?
1,2 A. Yes. One important change was the improved
13 economics of energy limited, non-dispatchable generation
1,4 that qualified as QPs. Wind, and later some forms of solar
l-5 became significantly more economic. In the case of wind,
l-6 this was due to several factors: wind turbine and blade
t'l technological improvements in the 1990s, a series of biIIs
18 in Congress that created and then extended significant
l-9 subsidies, additional subsidies in some states, and high
20 gas prices for much of the decade. These factors made
2L wind-powered generation approximately equal in cost to
22 conventional alternatives, at l-east for so Iong as
23 subsidies remained and gas prices were expected to remain
24 hiqh. As in the mid-1980s, bankable contracts based on
25 high fuel price expectations led to a new wave of PURPA
HTERONYMUS, DI 57
Idaho Power Company
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L2 wave of QFs had characteristics similar to the conventional
l-3 utility plant used in many states as a benchmark for
14 establishing avoided costs. Non-dispatchable, intermittent
15 resources have quite different characteristics. I wilI
l-6 opine later that these differences are so profound that
1"7 methods long used in a number of states for estimating
18 avoided costs are now categorically inappropriate.
activity, with a renewed "gold rush" in geographic areas
with good wind regimes and/or rel-atively high prices for
PURPA power.2o The growth of wind power has continued,
although substantial reductions in current and anticipated
gas price, the possibility of subsidies lapsing, and the
lack of adoption of national carbon legislation have
curtailed it in the recent past.
o.Does the nature of these new types of non-
dispatchable generati-on have importance for how avoided
costs should be established?
A.Yes. I stated earlier that much of the first
IV. AVOID@ COST IETEODS TN OEEER iIT'RISDICTIONS
o.You stated earlier that you would discuss the
2L various avoided cost methods in use. Please introduce this
22 sectj-on of your testimony.
23
20 While the efficient scale of wind farms approaches and may
exceed the upper limit of PURPA, developers often have been a]lowed tosplit the farms up into projects that are small enough to qualify.
HIERONYMUS, DI 58
Idaho Power Company
1 A. I will fi-rst discuss two studies that reviewed
2 avoj-ded cost practj-ces at different points in time. These
3 are an exhaustive survey of methods conducted by National
4 Economic Research Associates (*NERA"), a utility economJ-cs
5 consulting firm, in 1990 and a paper written by The Brattle
6 Group, also a utility economics consulting firm, for the
7 Edison Electric fnstitute (*EEI") shortly after EPAct was
B passed in 2005. I will also discuss a sampling of state
9 methodologies in use currently.
1-0 1990 Survey of Avoided Cost ldethodg
l-1- 0. Please describe the l-990 study.
L2 A. In 1990 NERA surveyed avoided cost
13 methodologies. They received responses from 60 utilities
L4 and 49 states.21 The results of the survey were published
15 i-n L992,22 and. covered both the marginal cost methodologies
16 used in setting retail electricity rates and the avoided
L7 cost methodologies used in setting prices paid to QFs.
1-8 Vflhile the survey is more than 20 years o1d, it still is
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2' Delaware did not respond.
22 Parmesano, Hethie and Bridgman, William, ?he Rofe and Nature of
IfiarginaT And Avoided Costs in Rateilaking; A Surveyt NERA, January 7992.
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Idaho Power Company
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representative of adminj-stratively determined avoided cost
methods in use today.23
O. Did the survey uncover a variety of methods
for setting avoided costs?
A. Yes. As stated earlier, EERC allowed states
quite wide Iatitude in PURPA compliance, including
selection of methods for determining avoided costs.
Moreover, in some states, regulators permitted utilities to
devise their own methodologies, so that more than one
existed. AIso, as in Idaho, some states employed different
methods for contracts of differing types or project sizes,
contract durations, and firmness of power deliveries.
O. Did NERA summarize the frequency of selection
of the various types of avoided cost methodologies?
A. Yes. NERA assigned the states' avoided cost
methodologies into five groups, apart from "other." lrlhile
there were only 49 states that replied, attri-bution numbers
are larger due to states that had multiple methods. The
groupings were:
1. Least-Cost Capacity Option. Attributed
to l-3 states. In this method, capacity value was based on
23 The exception is the use of bidding. As described previously,bidding r^ras sanctioned by FERC in a 1988 Notice of Proposed Rule Maklngthat did not ultimately become adopted into its regulations. Despitethe fact that bidding began in the l-ate 1980s as a method of selecting
new resources and determining price Levels paid to them, including QEs,the NERA survey does not dj-scuss any bidding-based avoided costmethodologies.
HTERONYMUS, Dr 60
Idaho Power Company
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the cost of a peaker.The peaker cost was net
of energy profits in at least some cases.'n Generally,
capacity cost was not credited to the QE until capacity was
needed by the utility.2s Avoj-ded energy was based on the
marginal dispatch cost of the utility, often referred to as
"system lambda."
2.Proxy Unit "A. " Attributed to l-1
states. Capacity costs were the capacity cost of the
avoided unit, sometimes but not always the next unit in the
utility's resource p1an. Avoided energy was based on the
cost of energy produced by the proxy unit. This is
conceptually similar to the fdaho SAR methodology.
3. Proxy Unit "B." Attributed to sj-x
states. This differs from Proxy Unit A in that any
capacity cost of the proxy unit that was in excess of such
costs for a peaker were not included in capacity value but
2a As discussed elsewhere, it is a very common practice today tooffset part of the carryj-ng cost of the avoided cost unit wi-th the
margins expected to be earned from sales of energy and ancillaryservices. This offset was less important in the 1980s for two reasons.
First, the significant improvement in technology that markedly lowered
the heat rate for new peaking plants had not yet occurred so that they
earned little if any margin on energy relatj.ve to the utility'smarginal cost/system lambda. Second, energy marglns in 1980s avoidedcost calculations were computed relatlve to system lambdas, notrelative to market prices as became more cornmon after the restructuringof the electricity industry in much of the country. If margins are
computed relative to system lambda, by definition there never is an
energy margin for the highest cost unit dispatched.
2s Excess capacity was rampant in the 1980s as a resul-t of loadthat was much lower than had be expected in the mid-l970s when
construction of long lead time, large (primarily coaL and nuclear)
baseload stations was initiated.
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rather were added to energy va1ue.26 If the proxy unit is
indeed more economic than adding a peaker, the avoided
capacity cost under this method should be at or below the
cost if the least cost capacity (peaker) method were used.
4.Differential Revenue Reguirements.
Attributed to 13 states. Avoided costs were calculated by
comparing the cost of the system with the QE included (but
treated as a zero cost resource) in comparison to the cost
of the system without the QF. This comparison was based on
the resource plan that existed if the QF did not exist.
This method could look similar to a least cost capacity
method, but if the QF merely postpones a utility unit
and/or if the QF is large enough to affect the utilities
system lambda, results will differ. Implicit in the
methodology, no capacity costs were included for years in
whj-ch capacity was unneeded. This is the method that NERA
attributed to Idaho in the survey.
5. Cost of Purchased Power. Attributed to
2 states. In both cases, purchased power costs were the
cost of economy purchases which at that time typically were
split-savings rates. The methodology bras used only for
26 The economic theory concerning utility resource selection isthat a utility that needs capacity will build the lowest capital cost
unit (i.e., a peaker). However, it will build another type of unitthat has higher capital cost i-n preference to a peaker if the energysavings vaLue of the alternative unit justifies its higher capitalcost. fn this sense, the higher capital cost for a baseload or
intermediate unit is for the production of energy, not for capacity.
HTERONYMUS, Dr 62
Idaho Power Company
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non-dispatchable QFs. Both states using this method used
Proxy Unit A for dispatchable contracts.
6. Avoided Energy Cost OnIy (No Capacj-ty).
Attributed to 15 states, including most states in the
Southeast. In a few cases, this treatment was limited to
short-term power sales, with other QFs treated differently.
It is possible that the prevalence of this method in 1990
reflected the large amounts of excess capacity that existed
at that time.
Masked by this grouping were differences in details.
One category worth mentioning was the assumption about QF
quantities used for computing avoided energy costs.
Methods varied from using energy cost sj-mulation assuming
no QFs, assuming the QF was in the resource mix, and (in
the Differential Revenue Requirements method) computing the
j-ncremental cost savings either for each QF individually or
the savings for all QFs collecti-vely.
lfhe Energy PoJ'icy Act of 2005 and the 2006 EEI Paper
O. What was the purpose of the 2005 EEI paper?
A. As PERC was considering how to implement the
relevant parts of EPAct, the Edison Electric lnstitute
weighed in with a commj-ssioned paper2' that characterized
the types of existing methodologies, identified
2' Edisonthe OriginaT,
Group.
Electric fnstitute, PURPA:
December 2006. The paper
Making the Seguel Better than
was prepared by the Brattle
HTERONYMUS, Dr 63
Idaho Power Company
L shortcomings and proposed changes. The passage of the
2 Energy Policy Act of 2005 and a requirement that EERC
3 implement changes in its regulations to reflect it had
4 sparked a renewed interest in avoided cost rate
5 methodologies. Because FERC had not made major changes in
6 its regulations since 1980, this was seen as an opportunity
7 to remedy elements of the FERC regulations that had been
8 shown to cause serious problems for the industry.
9 Q. What is the purpose of reviewing this paper?
10 A. This paper is a useful, albeit short, summary
11 of what had been learned about PURPA in the first 25 years
L2 of its operation. ft also provides a brief critique of the
13 avoided cost methods and contracts based on that experience
L4 and makes suggestions concerning how EERC could improve
15 PURPA Section 210 j-mplementati-on.
1-6 O. How does this paper classify avoided cost
L1 calculation methods?
l-8 A. The taxonomy of administrative methods for
19 setting avoided costs discussed in the EEI study was
20 similar to that used by NERA 15 years earlier. These were:
2t 1. The Proxy or Committed Unit Method.
22 This method, also called the proxy unit method in the NERA
23 paper, assumed that the QF delayed or replaced the next
24 planned generating unit in the utility's IRP. Avoided
25 costs were therefore based on the projected capacity and
HIERONYMUS, DI 64
Idaho Power Company
1- energy costs for that unit. Financing cost parameters and
2 discount rates for levelization were based on the utility's
3 cost of capital. Adjustments generally included modifying
4 capacity costs to account for in-service timing
5 differences. The authors noted that the proxy unit method
6 was one of the simplest types in that it did not require
7 production cost modeling. Implicit in that simplici-ty,
8 however, is that the avoided costs are not modified to take
9 into account differences such as availability and capacity
10 factor between the proxy and QE unit.
11 2. The Component/Peaker Method. This is
L2 what NERA termed the lowest cost unit method. The avoided
13 capacity cost is the lowest cost form of capacity,
L4 generally assumed to be a combustion turbine. The EEI
15 paper's description is silent on whether the capacity cost
16 was net of margins above variable cost earned j-n energy and
1,7 ancil-lary services markets. fn fact, most of the initial
18 adoptions of this method had no such offsets, which only
19 became important when improved turbine technology
20 substantially reduced heat rates and hence resulted in
2L operating profits for new peakers since market prices
22 and/or lambdas now were sometimes set by Iess efficient
23 units. The avoided energy cost is the utility's marginal
24 cost of generation over all hours of the year, but could
25 incl-ude only those hours when the QF wou1d produce power.
HIERONYMUS, DI 65
Idaho Power Company
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Implicit1y, the methodology assumes that the existence of
the QE does not affect the utilities' marginal cost.
3. Differential Revenue Requj-rements
Method. fn its most complex form, this method first
requires that the utility's expansion plan be reoptomized
to take into account the existence of the QF(s). The
existing system is then dispatched as is the reoptomlzed
system (with the QF treated as having zero costs).
Differential revenue requirements, including any
differences in capital costs, constitute the QF avoided
costs. This method differs from the component,/peaker
method in that it expressly determines the avoided capacity
within the analysis and inherently reflects the dj-spatch
pattern of the QF.
A11 of these methods identified above were
regulatory in nature. That is, avoided cost "discovery"
was based on calculations made or approved as part of a
regulatory process rather than by observing prices in the
market.28 As discussed previously, at the time that PURPA
was adopted, utilities hrere vertically integrated and there
hrere no organized power markets. Indeed, it was this lack
of competitive options for cogeneration and small power
28 An exception j-s that in the component/peaker and differential
revenue reguirements methods, the market cost of purchases could be a
component if, for example, the utility had an avoidable offer of
purchased power. I shall note that Sj-erra Pacific had complained thatthe Nevada Commission ignored this possibility in a proxy method
avoided cost computation.
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facilities that motivated Congress to include Section 210
in PURPA.
The EEI paper also discussed auctj-on-based avoided
cost methods. ft noted that auction-type procurements were
adopted largely in response to the poor performance of
administrative methods of avoided cost estimation. It also
stated that a primary reason for adopting auctions was to
limit the amount of QF energy and capacity purchased and to
be able to select the cheapest and/or most beneficial. It
noted that there was a great deal of variety in how
procurements were conducted, particularly in how scoring
was done, with self-scoring of bids according to previously
established, transparent scoring systems being at one
extreme and a whoI1y opaque, partly qualitative
determination of winners by the utility at the other. The
paper also discussed the portions of the FERC Aucti-on NOPR,
RM88-5, that discussed what types of auctions were
consistent with PURPA reguirements. The authors also
stated that the auction-based procurements that were used
by several utili-ties to meet their PURPA obligations were
generally conslstent with the NOPR, except that not all
embraced the proposed all-source requirements.
HIERONYMUS, DI 67
Idaho Power Company
1 Q. Did the paper comment on the advantages and
2 drawbacks of the various administrative methods of avoided
3 cost calculation?
4 A. Yes. The authors viewed the proxy unit method
5 as the l-east attractive method of determining avoided cost.
6 They noted that in many cases the proxy unit was not even
7 one that the utility would plan to build. Even if it was a
8 planned unit, the QFs being offered and getting a pri-ce
9 based on the proxy unit's cost may be too dissj-milar in
10 terms of, for example, reliability or the times when power
11 from the QE was available. They also noted that the proxy
1,2 unit method did not allow for reoptomizing the planned
13 system to take into account the output from QFs. This
L4 proved to be a major drawback in areas where QE entry was
15 substantial in relation to the size of the utility.
l-6 The differential revenue requirements method and the
1,7 component/peaker method were regarded as more sophisticated
LB and conceptually correct, but more complex and opaque. The
19 differential revenue requirements method also is the only
20 one that mode1s the impact of the QF on system lambda.
2L a. Did the authors comment on the performance of
22 these administrative methods collectively?
23 A. Yes. They stated that all such methods
24 require judgment about such uncertain factors as fuel cost,
25 cost of capital, escalation in labor and equipment costs,
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demand growth, and so forth. As it turned out, errors in
these forecasts, particularly fuel price forecasts caused
then-historic long-term avoided cost forecasts to be too
high irrespective of the method used.2e They note rather
wryly that proxy methods based on coal units likely were
the least wrong (despite the fact that few coal units were
actually initiated during the period) because the estimate
of coal price escalation was substantially l-ower than
similar estimates for oi1 and gas and hence closer to what
actually transpired.
O. Did the authors discuss the specific types of
errors that had been made in administrative avoided cost
approaches?
A. Yes. The authors grouped their comments under
six headings:
1. Intentionally Setting Rates Above
Avoided Costs. In a few cases, states deliberately set
rates above avoided costs. The example they use is the New
York six-cent minimum that the NYPSC Chair testified to
FERC was well above any of the state's utilities' avoided
cost.
2e It should be noted that such forecast errors are not limited to
administrative methods of estimati-on. If participants in an auctionhave a consensus of similarly incorrect expectations, auction-basedprices will be similarly wrong. The forecasting problem is not relatedto the method so much as to the enormous risk of forecasting and thenfixing prices, no matter what the method.
HIERONYMUS, DI 69
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2. Requiring Capacity Cost Payments Even
Though the Utility Does Not Need New Capacity. This was
discussed as primarily a consequence of standard offer
rates. However, the authors report that the California
Public Utilities Commission (*CPUC") deliberately required
capacity palrments when no capacity was needed to meet
reserve margin targets on the grounds that aII capacity
makes at least some contribution to reliability.
Limi-ts.
3. Standard Offer Rates Without Quantity
While FERC only required standard offer rates for
QFs of 100 kW or less, many states allowed standard offer
rates for larger projects. As noted previously, California
made its standard offer rates available to aI1 projects.
Since the rates \Arere very attractive to developers, the
state was swamped with projects.
4. Lonq-term Contracts with Fixed Rates.
As the authors had already noted, forecasts of long-terrn
prices will inevitably be wrong. V{hile it can be hoped
that the errors will even out to zero, this has not been
the experience. While comments received by EERC in 1987
had argued for reopeners or other methods for limiting
Iong-term contract price risk, FERC had not acted to limit
the ability of states to require long-term contracts. A
related problem noted in the paper was the front-Ioading of
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costs that raised intergenerati-onaI equity and out-year
performance risk issues.
5. General Errors in Avoided Cost
Methodology. This was a catch-all category. Two examples
were given. One relates to proxy unit methods where the
avoided cost unit was one that actually was under
construction. In such cases, the authors argue that the
sunk costs of the unit should not be included in avoided
cost calculations. The second example was failure to take
power purchase alternatives into account in setting avoided
costs. The example given was in Nevada; there the rate was
set at 6.3 cents, notwithstanding that the utility's
planned next addition was a firm purchase at a much lower
cost.
6. Paying the Same Rate to QEs, Reqardless
of Their Characteristics. From the historical perspective
taken in the paper, this problem arose primarily from the
baseload-Iike nature of most QFs built in the earlier years
of PURPA. Since QFs had the right to be paid for a1I power
generated, and prices were above the units' marginal costs,
these units performed like must-run baseload units. In
areas where quantities grew large enough, or where the
utility already was long basel-oad generation, this created
operatJ-onal as well as financial problems for the
utilities. While dispatchability had been one of the
HIERONYMUS, DI 7L
Idaho Power Company
1 factors that FERC had expressly called for states to take
2 into account in setting avoided cost rates, in the states
3 discussed in the paper there was no price differentiation
4 for dispatchabl-e units. Of course, this problem remains
5 since these are characteristics of wind and solar power.
6 Q. What does the report say was the response to
7 these errors?
8 A. The primary response that the paper discussed
9 was the development of competitive procurement as an
L0 al-ternative to administrative methods. The report
11 acknowledges that this is not a panacea, since long-term
L2 fixed prices can lead to serious over (or under) payment no
13 matter how set. Nonetheless, the authors conclude that
L4 "prior to the industry disruption caused on retail
15 competition and restructurj-ng, competitive procurement of
16 QE capacity was exhibiting promise as a means of correcting
L7 some of the problems associated with administratj-ve
18 determinations of avoided costs."
19 A SarpJ.ing of Curent Avoided Cost Methods
2A O. Thus far, you have discussed primarily the
2L avoided cost methods that were established in the 1980s.
22 Have you also reviewed some of the innovations that have
23 taken place since that time?
24 A. Yes. I will focus particular attention on
25 California. It had one of the most painful experiences
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resulting from having made mistakes
in the 1980s and hence is likely to
learned.
PURPA implementation
mindful of lessons
in
be
I do not suggest that California is the template for
Idaho to folIow. The California solution was a compromise
among interests and, Iike all compromises, is not perfect.
Further California had characteristics not necessarily
shared by ldaho: a large installed base of QFs coming up
for recontracting and a very aggressive renewables
requirement being two obvious examples.
Other states have meritorious solutions to the
avoided cost problem that also are worthy of consideration.
I wiII discuss a sampling, highlighting features that I
believe to be of particular interest or merj-t.
o.Please provide some background on the
reformatj-on of the California methods of determining
avoided costs.
A. As discussed previously, California has very
substantial amounts of PURPA power. Much of that capacj-ty
was signed up under Standard Offer 4 (*SO4"). SO4 fixed
forecasted energy prices just before gas prices collapsed
and hence was highly profitable, particularly but not
uniquely for gas-fired cogeneration. So4 had no ceiling
quantity amount and, according to Southern California
Edison, by early 1987 caused total QE contracts in
HIERONYMUS, DI 73
Idaho Power Company
1 California to rise to 16,000 MW, notwithstanding that S04
2 existed only from April 1983 until it was suspended in
3 September l-984. SO4 QFs received 10- to 30-year contracts
4 with fixed capacity payments and L0 years of predetermined
5 energy payments. The very high costs and substantial
6 amounts of capacity were j-l-lustrated in comments provided
7 to the FERC in 1987. For example, Pacific Gas and Electric
8 Company ("PG&E") testified at a FERC-sponsored regional
9 conference (memorialized in FERC Docket No. RM87-12-000)
10 that by 1990 its QF overpalrments would reach an estimated
11- $857 million per year. It cited to a California Energy
12 Commission estj-mate made in 1986 that, as a result of its
L3 QFs, PG&E would need no new capacity before the late 1990s.
1,4 At the time that settlement talks brere underway,
L5 many of the QF contracts were expiring and projects were
l-6 seeking new contracts, to which they were entitled under
L1 PURPA. During this same time frame, California was
l-8 adopting numerous "green" policies, including renewable
19 quotas, such as separate utility quotas for different types
20 of renewable and cogenerated power. On the other side, in
2L implementing EPAct, FERC had invited the California
22 utilities to apply for exempt status, which would result in
23 existing QFs losing PURPA as a basis for demanding
24
25
HIERONYMUS, DI 74
Idaho Power Company
L contracts altogether.30 This confluence of events created a
2 climate for a settlement covering utility procurement of
3 both QEs and other, non-QF cogeneration and renewable
4 power.
5 California utilities, cogeneration and combined heat
6 and power QF owners, and ratepayer advocacy groups
7 negotiated for 16 months and entered into a settlement
8 Agreement (*QFICHP Settlement") approved by the CPUC in
9 December 2010. The QFICHP Settlement resolved QF-related
10 disputes before the CPUC and the courts, established a new
l-1 QF/CHP Program in California, made available additional
12 power purchase agreement ("PPA") options for QEs under the
13 QFICHP Program, including a PURPA program for new PPAs for
L4 QFs of 20 MW and smaller, and established a transition
l-5 phasing out QF status for QEs with greater than 20 MW net
1-6 output.
L1 fn June 20L1, FERC found that the utilities in the
18 California Independent System Operator ('ISO") qualified
t9 for exemption from PURPA Section 210 purchase requirements,
20
30 In its 2006 Order, FERC determined that the exemptj-on would notapply, even for the five RTOs entitled to exernption, for QFs with
maximum capacities less than 20 MV{. The 20 MW limit was very differentfrom the statutory 100 MW entitlement to a rate based on a schedule.
f t is interesting that in '1,98'7, FERC had opined that l- MW was an
appropriate limit for exempting QEs from having to participate in all-source procurements for states that had such methods for procuringpower. It is not cl-ear why utilities are belj-eved to need to serve as
aggregators for small QFs. The reason may be that the RTO membershipfees are substantial.
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with the exception of QEs smaller than 20 MW for which
exemption had not been sought.
a.Please explain the main attributes of the new
California procurement of cogeneration and renewable povrer.
A.The settlement has various procurement
mechanisms. It should be understood that the settlement is
not just about PURPA QFs, but also about non-QF renewables.
Under the QE/CHP settl-ement, a new, competitive procurement
process was adopted in lieu of the previous system of PUC-
ordered standard offer contracts. A primary mechanj-sm
created in the QFICHP Settlement is a CHP Request for
Offers (''RFO") process that a11ows the state's three large
utilities to run competitive, transparent REOs for CHP
resources. It puts CHP resources into a process similar to
the competitive procurement processes that already had been
established for conventional resource and Renewable
Portfolio (*RPS") procurement. The settlement also allows
utilities to use non-RFO processes such as bilateral
contracting, renewables feed-in tariffs, a PURPA Program
for QFs under 20 Mtf,, direct utility ownership, and other
procurement options. Allowing CHP developers to bid into
the RFO allows them to propose prices that are sufficient
to finance and develop their facilities, while at the same
time allowing the IOUs to pick the best offers based on a
number of criteria, including price.
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The QEICHP Settlement further establishes
procurement "MVil Targets" for each of the California IOUs
under the QF/CHP Program. Overall, the target is 3,000 M[,I
of new or repowered projects for the decade beginning 2010.
O. Does California have a standard offer specific
to QFs?
A.Yes. The pro forma PPA for QFs of 20 MW or
less is available to QFs with firm or as-avail-able capacity
of less than 20 MW, regardless of whether the QF has
submitted an offer in the REO or seeks alternative
contracting options. The PPA for QFs of 20 MW or less
contains standard terms and conditions and incorporates the
peaker-based capacity prices established in prior PUC
decisions.3l For energy prices, the QF/CHP Settlement
establishes Short-Run Avoided Cost (*SRAC") that
transitj-ons to a market (rather than administratively
determined) heat rate by January 1, 2OL5.32 New or
repowered facilities must post project development security
and performance assurance. The term is up to 7 years for
existing capacity, and up to 12 years for new capacity.
31 Capacity pricing is pursuant to D. 07-09-040, with Firm
Capacity at $91.97lkw-yr and As-Available CaPacity of $41.22/kW-yt
escalating each year.
32 The Cafifornia Public Utilities Commission has set SRAC
energy prices using a variation of the following formula for manyyears: SRAC Energy Price : Fuel Price x Heat Rate + O&M Adder. The
regulatory heat rate in existence at the time of the settlement was i.n
excess of 9000 BfU/kWh, which was higher than the heat rate implied by
the market price of power.
HTERONYMUS, Dr 77
ldaho Power Company
1 QEs of 20 MW or less are included in the Procurement MW
2 Targets for each of the California IOUs, so that while
3 there is no limit on QPs as such, the 31 000 MW overall
4 limit is in force.
5 QFs with as-available capacity receive SRAC energy
6 palrments along with an as-available capacity payment. QFs
7 providing unit firm capacity also receive SRAC energy
8 payments and higher capacity payments reflect the value of
9 assured long term firm capaclty.
10 The standard terms for new PURPA contracts are
L1 essentially identical to the contract terms for non-QF
1,2 CHPs. The capacity price component is set in advance for
13 the length of the contract (L2 years for new or repowered
14 capacity). The performance requirements to qualify for
l-5 firm capacity payments are steep: earning a fu1l payment
16 requires an availability of 95 percent and no payment is
L7 available for availabilities of less than 60 percent. As-
l-8 available capacity palrments also are subject to non-
19 availability penalties.
20 O. Are energy palrments fixed for the duration of
2L the QF contract?
22 A. No. An important change from prior Californj-a
23 QF contracts is that energy prices are reset annually
24 rather than fixed in advance for the term of the contract.
25 The SRAC price is set based on L2 months of forward
HIERONYMUS, DI 78
Idaho Power Company
1 prices.33 Both capacity and energy prices are time
2 differentiated into two seasons and several time-of-use
3 periods.
4 Q. How does the QF contract treat the green
5 attributes of QF contracts?
6 A. The contracts entitl-e the buyer to all energy
7 and capacity from the QF as well as all of the green
B attributes of the power production. The price paid for
9 energy from the QF includes any greenhouse gas charges that
10 may be assessed on it based on its fuels type and
11 efficiency.
\2 0. Does California have other renewable resource
13 program specific to PURPA qualifying resources?
L4 A. Yes. The Renewabl-e Auction Mechanism, or RAM,
l-5 is a market-based procurement mechanism for distributed
L6 renewable generation projects up to 20 MW delivered on the
t7 system side of the meter. The California PUC authorized
1-8 the utilities to procure an initial 1,000 MW through RAM.
19 Under the market-based pricing in the RAM, sellers compete
20 for a contract in a renewable auction mechanism, bids are
33 Due to a peculiarity of California law, the energy prices must
be indexed to gas prices. Between 2011 and 2015, the heat rate used toconvert forecast gas prices to electricity prices declines to the
"market heat rate." The market heat rate is the heat rate implied bythe 12 month forward electrj-city prices in the relevant zone (northern
or southern California). The effect of using a market heat rate, sodefined, is to convert the gas pri-ce formula to one that prices energy
based on the forecast electricity prices in the zone, as forecasted bythree separate commercial services and based principally on forwardbilateral transaction prices.
HIERONYMUS, DI 79
Idaho Power Company
1 selected by least-cost price first untlL the auction
2 capacity is reached. Eurther negotiation is not alIowed.
3 The price is the as-bid price of the QF, not a market
4 clearing price for the totality of winning bids.
5 Q. Does California have a program for buying QE
5 power on the basis of schedules, as PURPA requires for
7 resources of less than 100 kW?
B A. Yes. Eor smaller scale renewable resources,
9 "feed-in tariffs" are used to purchase power under
10 predefined terms and conditions, without contract
l-1 negotiations or participation in a competitive
L2 solici-tation. Use of feed-in tariffs are restricted in
13 terms of the types of QFs that qualify to a maximum size of
L4 1.5 MW and aggregate quantity (initially, Iess than 500 MW,
L5 statewide).
l-6 O. You had said earlj-er that California had been
L7 a poster child for excess prices and quantities of PURPA
18 power in the L980s. What are the primary areas of
19 j-mprovement in the current California avoided cost
20 methodology2
2t A. First of all-, since only projects of less than
22 20 MW are elj-gible for PURPA-based contracts, the
23 likelihood of great excesses of unneeded power is much
24 reduced. Second, California quit requiring utilities to
25 offer pre-determined energy prices in their long-term
HIERONYMUS, DI 8O
Idaho Power Company
1 contracts. While contracts are up to 12 years long (a
2 shorter period than under the earlier standard offers),
3 energy prices are set only one year in advance.
4 Effectively, they are based on market energy price
5 forecasts. Prices are time-differentiated so that the
6 energy price received by the QF depends on when energy is
7 produced. Capacity prices are set at contract inception
B for the full term, but are varied according to the firmness
9 of capacity, plant availability, and the time at which
10 energy is produced by the QE.
11 The California QF contracts are non-discriminatory
L2 in that QFs are paid on a basis very similar to non-QF
13 projects. That is, there is litt1e advantage to qualifying
L4 as a QE since essentially identical contract terms are
15 available under other state programs for non-qualifying CHP
L6 and renewable power. Moreover, since the bulk of CHP and
L'7 renewable power is not PURPA eligible, there j-s no
18 impediment to the state limiting the total amount of such
L9 power to that which is needed for reliability or to meet
20 other state objectives since QFs count toward the relevant
2L overaLl targets.
22 An exception to the lack of long-term fixed prices
23 is the program for purchases of renewable power from
24 projects of less than 1.5 MW. However, eligibility under
25 this program is severely quantity limited.
HIERONYMUS, DI 8]-
fdaho Power Company
1- Q. Are there aspects of the California solution
2 that will pay QFs prices that are above avoided costs?
3 A. This is matter of interpretation. It had been
4 long-standing FERC policy that avoided cost had to be set
5 with reference to all potential sources of power. This was
6 applied specifically to California in a FERC order in case
7 EL95-16-001. This decision found that a CPUC order
8 requiring utilities to buy QF power in an auction process
9 in which participation was limited to QFs violated PURPA,
10 since prices determined in such an auction could exceed
11 prices available from non-QF alternatives. By this
L2 standard, the renewables-only auctions in the current
13 California scheme can result in overpalrments.
L4 However, as part of revisiting PURPA and renewables
15 development that I have just discussed, the CPUC petitioned
16 FERC for determination of whether feed-in tariffs and other
Ll mechanisms limited to QEs violated PURPA. In EL10-64-001,
18 FERC essentj-a1ly reversed its earlier order. ft reasoned
19 that when a state had a renewable portfolio standard, power
20 from sources that do not qualify as renewable cannot be
2L used to meet the requirement. Hence, the lowest cost
22 available resource that qualifies as renewable is the
23 avoided cost for meeting the RPS requirement. Hence, a
24 competition restricted to renewable resources can validly
25 set an avoided cost that is consistent with PURPA.
HIERONYMUS, DI 82
Idaho Power Company
1 Erom thi-s I infer that the mechanisms created in
2 California for estimating the PURPA avoided cost for
3 renewables that allow payments greater than made to non-
4 renewables are Iawfu1, at least in California. However,
5 their validity would seem to depend on the existence of a
6 bright line renewable resource procurement requj-rement with
7 firm and specific renewable resource quotas and based on
8 the ELI-I-0-64-001 would seem to be valid only under those
9 circumstances.
10 Innovations in Various Ottrer States
11 A. What is the purpose of this sectlon of your
12 testimony?
13 A. While I have discussed the categories of
14 avoided cost methods, there are important details within a
15 type of method that Idaho may wish to consider. I have
l-6 reviewed several different avoided cost methodologies and
L7 extracted some of the features of them.3a
l-B O. What is the first topic you will discuss?
19 A. The first topic is the use of visible market
20 prices for calculating avolded costs.
2L As I discussed previously, the Energy Policy Act of
22 2005 mandated that utilities in the five original RTOs were
34 Reviews were either from original source documents or from
summaries contained in a 2011 study sponsored by the Southern A1liancefor Clean Energy, authored by a Ms. Carolyn Elefant, titled "Reviving
PURPA's Purpose: The Limits of Existing State Avoided Cost RatemakingMethodologies in Supporting AJ-ternative Energy Development and A
Proposed Path for Reform." available at www.carolynelefant.com.
HTERONYMUS, Dr 83
Idaho Power Company
1 eligible for exemption from PURPA section 210 altogether.
2 Hence, projects that prevJ-ous1y would have been QEs in
3 those areas are dependent on either bilateral contracts
4 with utilities or the visible markets conducted by the RTOs
5 for revenue. Most such contracts are short run in nature;
6 state-supervised auctions typically are for three years or
7 1ess. RTO power markets are even shorter term, with prices
8 varying even within the hour and prices set at most a day
9 ahead. Capacity typically is bought on a monthly,
10 seasonal, or annual basis in those RTOs that have capacity
1l- markets.
L2 Power markets are also used in several instances to
13 set avoided cost rates where the utility is not exempt.
t4 California is one example. Energy prices for QFs except
15 the smallest ones are set based on one year forward market
16 prices. Other states using market prices for at least some
l7 QFs include utilities in RTOs in the period prior to
18 exemption, for which Massachusetts is an example,
19 Southwestern Public Service (*SPS"), which is in an RTO but
20 is not exempt, Oregon, which uses market pri.ces for energy
2L when a utility does not need capacity, and Progress Energy-
22 Carolinas, that offers market prices as an option that a QF
23 can select.
24
25
HIERONYMUS, DI 84
Idaho Power Company
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4
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9
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O. How did Massachusetts set avoided cost prices
prior to the blanket PURPA exemption for ISO-New England
utilities ?
A. Massachusetts was one of the earliest states
to restructure. Its utilities sold their generation and
bought thei-r provider of last resort power from ISO
markets. These same markets were available to all power
suppliers, including QFs. When Massachusetts utilities
stil1 had obligations to purchase from QEs under PURPA,
they h/ere allowed to satisfy the obligatlon by taking title
to the power, and paying the ISO-NE spot energy price at
the QFs location for power, as well as the locational price
for capacity set in the ISO-NE market.
a.Please explain how SPS uses market prices to
set avoided costs.
A.SPS is a member of the Southwest Power Pool
("SPP"). SPP utillties did not qualify automatically for
exemption, but FERC invited 1ts members (similarly to the
CAISO member utilities) to apply for exemption. SPS and
two other SPP member utilities applied jointly for
exemption i-n 2008. While the other two utilities gained
exemption, FERC found that QFs in SPS might not have
sufficient access to markets to cause EERC to grant an
exemption. SPS continues, therefore, to be required to buy
QF power under PURPA. However, both the Texas and Oklahoma
HIERONYMUS, Dr 85
Idaho Power Company
1 state regulators have concluded that SPS can meet its PURPA
2 responsibilities by buying power from the QEs and paying
3 them the price they would receive if they sold into the SPS
4 balancing market. The reasoning is that the sole cause of
5 SPS being denied exemption is because of market access
6 concerns, not concerns over the appropriateness of market
7 prices as measures of avoided costs. SPS's agreement to
8 pay the market price irrespective of whether the power
9 could be deLivered outside of its BAA solved the market
1-0 access problem.
11 O. How does Oregon use market prices to set
L2 avoided costs?
L3 A. Oregon distinguj-shes between avoided cost
L4 methods for near-term periods when utilities have
15 sufficient resources to meet reliability requirements and
16 longer term periods when new resources are needed. Oregon
77 uses the proxy methodology for the future, resource deficit
18 periods. It uses monthly on-peak and off-peak forward
19 prices as of the time of contract signing for the near
20 term, resource adequate period. No capacity payment is
2L made during that period.
22 O. How are market prices used in North Carolina?
23 A. In North Carolina each utility has its own
24 primary method for setting avoided costs. Both the peaker
25 and IRP methods are permitted. Progress Energy uses the
HIERONYMUS, DI 86
Idaho Power Company
1 IRP method. It offers standard contracts for units up to
2 five MW (three MW for hydro) with the standard contract
3 based on a generic version of the QE type (e.9., solar,
4 municipal waste, or wind). As an alternative, the QE can
5 elect to be paid the locatj-ona1 marginal price calculated
6 by the Pennsylvania-Jersey-Maryland (\\PJM") RTO at its
7 interconnection with Progress Energy. This is somewhat
B different than for SPS and the Massachusetts utilities
9 since Progress Energy is not in P,JM. Rather, PJM is used
10 as the closest market with a competitively set, visible
l-1 market price.
L2 O. Do you have any examples of utilities using
13 auction or RFP methods to set prices?
1,4 A. Yes. An example is Georgia using competitive
1-5 bidding to set its avoided costs. The RFP quantity is
16 based on the utility's needs. A11 QFs of five MW or more
L7 must bid in response to the REP and receive a contract only
18 if they are winning bidders. Sma1ler QEs can get the REP
19 price without participating.
20 O. Can you provide any examples of creative
21 approaches using administratj-ve methods for setting avoided
22 costs?
23 A. Yes. Florida uses the next unit proxy unit
24 method. What differentiates Florida from most other states
25 using the method is that it is quite literal about using
HIERONYMUS, DI 87
Idaho Power Company
L the utility's next unit as the proxy, j-n that the proxy
2 unit is changed in response to changed circumstances,
3 incl-uding contracting with QFs.
4 Each utility must identify the next avoidable unit
5 in its resource pIan. Avoided capital costs are based on
6 the savinqs from deferring the unit, essentially the annual
7 carrying costs, escalating at the construction cost
8 escalation rate. If the avoided uni-t i-s on line well into
9 the future, capital cost payments can begin at a time
l-0 before the on-line date of the avoided unit, reflecting the
l-l- need to commit resources to its construction if it is not
L2 avoided. Avoided energy costs are the energy costs of the
13 avoided unit beginning when the avoided unit would have
t4 come on line. For periods before the on-line data of the
15 avoided unit, only as-available energy payments are made.
16 These are the ex post actual avoided costs arising from all
L7 of the QFs that are receiving as-avallable rates, averaged
1-8 over the block of a1I such capacity. This is not the
t9 system lambda for two reasons. First, this averaging will
20 reduce the energy price relative to a system lambda.
2L Second, the calculation is made after first eliminating the
22 energy used to serve interchange sales. That is, only the
23 cost of energy that is avoided in meeting natj-ve load
24 counts, as available QFs do not receive the higher cost of
25 energy that only is generated to make off-system sales.
HIERONYMUS, DI 88
Idaho Power Company
l- Q. Does the Elorida QF offer system include
2 tariff-like standard contracts?
3 A. Yes. These are available only to units of 100
4 kw or 1ess. The regulations appear to contemplate that aII
5 other contracts are negotiated. The utility is not
6 required to pay more than its avoided costs and must
7 negotiate in good faith. The Commlssion may order the
8 util-ity to sign a contract and penalize dealing in bad
9 faith.
l-0 O. Can Florida utilities limit the amount of QE
11 capacity that they purchase?
12 A. Not directly, but there are specific
13 mechanisms to change (1ower) the price when sufficient
t4 capacity has been contracted.
15 O. How does this mechanism work?
16 A. The proxy unit used to set avoided cost is a
1,7 specific planned unit with defined capacity. The standing
1-8 offer to QFs arising from the avoidance of that unit closes
l-9 whenever an REP to actually construct that unit is issued,
20 when the amount of capacity needed to fully displace that
2L unit has been contracted, or when the unit is removed from
22 the utilities' resource plan for other reasons.
23 Closing the o1d offer triggers a new avoided cost
24 based on what becomes the utilities avoided unit.
25 Necessarily, this unit will have a later on line date than
HTERONYMUS, Dr 89
Idaho Power Company
1 the unit that previously had set avoided costs. Usually
2 this new avoided cost will be less attractive to QEs, if
3 for no other reason because the period of time that will
4 pass during which the QF receives no capacity payments and
5 receives only ex post short run incremental cost for energy
6 wil-l- be longer.
7 Q. What lessons do you draw from these examples?
8 A. From the examples of non-exempt utilities
9 basing payments on actual market prices, I infer that this
10 practice is acceptable to FERC and to at least some state
1l- regulatory commissions. From the Georgia example, I note
L2 that utilities still can rely on competitive procurement
13 for limited quantities of energy and reject QF offers
14 (other from small units) that do not wi-n in the
15 procurement. From the Florida regulations, I see that even
16 proxy unit methods can result in limiting QF energy
l7 purchases and, at Ieast in principle, avoid buying unneeded
18 capacj-ty or paylng more than avoided costs. The Elorida
19 example also is interesting in its treatment of QE energy
20 received before the avoided unit would have been on-line
2L and in j-ts exclusion of j-nterchange sales in setting short
22 run avoided cost of energy.
23
24
25
HIERONYMUS, DI 90
Idaho Power Company
1- V. CURRB{T AVOIDED COST OPEIONS A}ID RECOIOIEIIDAXIONS2 EIOR IDAEO' S A\TOIDED COST }TETEODOI,oGY
3 Characterization of Types of, lletho&
4 Q. You have discussed various methods of
5 calculating avoided cost at some considerable length.
6 Would you please very briefly restate what categories of
7 methods exist?
B A. Presently there are two types of methods of
9 determining avoided costs: administrative/regulatory
10 determinatj-on and market revelation. Each can, in turn, be
1l- divided. To summarize:
12 1. Administrative/Regu1atory.
13 a. Proxy Unit. There are several
14 variants on this method; the core is that avoided costs are
15 based on the capital costs and variable operating costs of
16 a proxy unit which may be the next unit in the utilities
l7 resource p1an, and commonly is a combined cycle or
1B combustion turbine unit.
19 b. System simulation/IRP. The pure
20 variant of this method requj-res injection of the QF into
21, the utilitlr's preferred resource plan, then reoptomizing
22 new builds and resimulating system cost. Avoided cost is
23 the difference between the two streams. A simpler version
24 assumes that the next unlt would have been a peaking unit
25 and computes the capacity value of the QE based on the
26 capital cost of the peaker, preferably calculated net of
HIERONYMUS, DI 91
Idaho Power Company
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2t
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25
energy and ancillary services net revenues and adjusted for
the on-peak availability of the QF. The QF's energy
avoided cost is, as with the pure varj-ant, based on
simulation of marginal energy costs for the utility, but
assuming that the incremental costs without the QF wiII
also be the incremental costs when it is on-line.
2.Market Discovery.
a. RFP/Auction. The utility holds
competitive procurement for a defined amount of power. The
price set in the procurement is the utility's avoided cost,
though non-price factors can be taken into account in
selecting winners. The price usually is available to QFs
only if they are winners in the auction. While EERC
favored all-source procurements for such procurements, its
recent EL10-64-001 decision (discussed in connection with
California's avoided costs) allows auction arrangements
limited to certain kinds of resources such as wind or solar
under defined circumstances.
b. Market Pricing. This effectively
is the substitute for avoided cost pricing and contracts in
areas where PURPA exemption is available. As discussed in
connection with SPS's Oklahoma and Texas tariffs, and
Progress Energy's North Carolj-na's tariff, it also can be
used where QE access to markets cannot be assured, but
HTERONYMUS, Dr 92
Idaho Power Company
1 relevant competitive markets can be used as a benchmark for
2 pricing PURPA polrer.
3 Q. Which of these methods currently is used in
4 Idaho?
5 A. My understanding is that ldaho currently uses
6 the proxy unit in its SAR methodology for smaller units and
7 the simpler version of the system simulation/IRP method for
8 larger units.
9 Digcussion of, Avoj,ded Cost Ca].cul'ation liethods
10 O. You have discussed four tlpes of methods of
11 determining avoided costs. Is there a hierarchy in terms
'J"2 of how well they comport with the basic PURPA requj-rement
13 that prices be at, but no higher than, the util-ity's
1,4 avoided cost?
15 A. Market-based solutions are congruent with this
L6 reguirement, almost by definition. Whether a price can be
L7 readily observed, as in the RTOs spot markets, or must be
l-B discovered, as in the structured procurement method,
19 depends on where the utility is located. While a case can
20 be made, and FERC at one time made that case, that market-
2L based solutions are better than even the best
22 administrative solution, market forecasts are simply
23 consensus forecasts and have no per se cl-aim to superiority
24 over a properly conducted forecast made in the course of
25
HTERONYMUS, Dr 93
Idaho Power Company
L the utility's business or conducted as part of a regulatory
2 or administrative process.3t
3 Setting aside issues of convenience and
4 transparency, which may be controlling for very small QEs,
5 the preferable adminj-strative method is the IRP method.
6 The proxy unit method is clearly inaccurate, at least under
7 today's circumstances. Various forms of the proxy unit
B method were initially the most commonly adopted. The
9 virtue of the proxy method is simplicity and transparency.
10 The method does not require forecasting the operation of
11 the utility's system, but only the operating cost of the
L2 proxy unit. A single schedule of prices is derived and
13 available for application to all QFs. This simplicity is
14 also its Achilles Heel. Quite simply, it ignores the fact
15 that different types of QFs have very different operating
16 characterj-stics and hence allow the utility to avoid very
L7 different costs. This particularly is true of intermittent
l-8 resources such as wind and solar and non-dispatchable
l-9 and/or energy limited resources such as some hydroelectric
20 facilities. I understand that these are likeIy to be the
2L most common types of QFs in Idaho in the near future.
22
3s FERC's clalm of superiority for auction methods of settingprices did not rest on the assumption that auction participants werebetter forecasters than utilities or regulators, but on the observationthat if the utility actually purchased the lowest cost power offered toit, it was paying a proper avoided cost price for the product that wasthe subject of the auction, at least at that time.
HIERONYMUS, Dr 94
Idaho Power Company
1 Q. How are today's circumstances different from
2 those that existed when most states adopted some form of
3 proxy unit method?
4 A. There is a much greater mismatch between the
5 characteristics of a proxy unit and the types of units
6 being offered as QFs. A proxy unit anywhere in the U.S.
7 most likely would be a gas-fired combustion turbine or a
8 gas-fired combined cycle unit. Compared for example, to a
9 wind farm, these types of units have excellent reliability
10 and availability and hence value as capacity, and the
1l- ability to provide important ancillary services. Combined
t2 cycle units also are economic producers of energy much of
13 the time, whereas the energy value of combustion turbines
1,4 is limited as a result of high dispatch costs. Conversely,
15 a wind farm has very little capacity value due to the high
16 proportion of time when it cannot produce energy and a lack
l7 of diversity to other wind units, litt1e if any positive
18 ancj-llary services value and, indeed, impose integration
19 costs arising primarily from the need for the utility to
20 carry additional regulation. On the other hand, its energy
2l production value t1pica1ly is substantially greater than
22 the combustion turbine and may be greater than a combined
23 cycle unit where wind regimes are favorable and combined
24 cycle units are uneconomic for significant portions of the
25 year.
HIERONYMUS, Dr 95
Idaho Power Company
l- Q. Is it possible to adjust the proxy unit-
2 derived avoided cost to create a reasonable estimate of the
3 avoided costs applicable to the types of units that are
4 seeking PURPA contracts?
5 A. To some degree, yes. For example, the
6 capacity value of the QF can be adjusted from the proxy
7 unit to reflect different availability. However, there
8 stil-I are important other differences that should be
9 reflected in avoided cost but will not be. Use of a common
10 proxy unit also distorts the relative avoided cost of
1l- dif ferent types of QEs. For example solar po!.rer produces
1,2 energy that is disproportionately during high load periods
l-3 but wind does not.
L4 It could be argued that there is a place for a proxy
15 unit for the rate schedule used for small QFs. This is the
75 practice in Idaho, where the SAR-derived schedule is based
l7 on a proxy unit. However, using a single type of proxy
18 unit still results in the same proportionate distortion as
19 if the proxy unit method were applied universally. The
20 size limit merely confines the damage.
2L Eortunately, there is no need to use a proxy unit,
22 even for the published rate schedules that must be made
23 availabl-e for sma1l units. There is not, and never was, a
24 requirement for a single rate schedule for small QEs, much
25 less a single proxy unit. Instead, the set rate schedules
HIERONYMUS, DI 96
fdaho Power Company
1 can be developed separately for each of the main tlpes of
2 QFs. My understanding is that in Idaho these are wind
3 power, irrigation-based hydro, and so1ar. Basing the rate
4 schedule for wind QFs on a generic wind unit's avolded cost
5 and a solar schedule on a generic photovoltaic unit's
6 avoided cost, for example, greatly improves the accuracy
7 and non-discrirninatory nature of the schedules. A set of
8 rate schedules that computes avoided costs with reference
9 to the operating characteristics of generic units of the
10 differing QE technologies makes use of the system
1-l- simulation/IRP method instead of the proxy unit method.
t2 This is an element of the IPC proposal in this proceeding.
1-3 O. Skipping over the system simulation method
14 which I understand to be the primary focus of your
15 recommendations, what are the virtues of the market-based
16 methods?
t7 A. Congress has determined that access to
18 transparent and liquid markets achieves the goals of PURPA.
19 This is reflected in the exemption of utillties in
20 organized RTO markets from PURPA Section 210 obligations.
2t Similar access to a liquid and transparent market outside
22 of an RTO should be similarly sufficient to achieve the
23 intended non-dj-scriminatory effect. In the fdaho context,
24 the closest transparent and visible market price is the
25 mid-Columbia price. If the state's utilitj-es were to pass
HTERONYMUS, Dr 97
Idaho Power Company
1 through revenues that were based on the mid-Columbia price
2 (with appropriate power firming, system integration, and
3 transmission cost adjustments), the resultant avoided costs
4 would be identical to the revenues that the QE would
5 receive if Idaho were part of a market in which util-ities
6 qualify for exemption. This pricing could be done on an ex
7 post basis. It also could be on an ex ante basis for up to
8 two or three years (as is the case in Oregon), since
9 reasonably thick and liquid markets exist for that period.
10 Access to these forward markets permits both price
11 discovery and an opportunity for the utilities to hedge
L2 their price commitments. If done on an ex post basis, thi-s
13 is essentially the result that would ensue if the Idaho
L4 utilities were exempt. The ex ante solution provides the
15 QE with somewhat greater price certainty, without unduly
16 burdening customers with price risks.
l7 A. Do you believe that this type of price
18 discovery would be found by FERC to be consistent with
19 PURPA, even if the Idaho utilities are not eligible for
20 exemption?
2L A. Most likely, y€s, but this is not entirely
22 certaln, particularly since the current FERC strongly
23 promotes renewable generation and demand response as
24 alternatives to fossil generation. But on the merits, it
25 should be acceptable. Under this option, the market
HTERONYMUS, DI 98
Idaho Power Company
1 pricing of QF power is non-discriminatory, in that the QF
2 gets a price based on the market price of power at which
3 the Idaho utilities can and do buy and seII non-QE power.
4 It also assures that Idaho ratepayers are not disadvantaged
5 by paying more for power than they would pay non-QE
6 sources. af, as it likely must be, market pricing is
7 either ex post or based on forward markets that do not
8 extend far into the future, it can essentially eliminate
9 long-term contract risks.
10 O. What would your response be to the argument
11 that these short-term, market-based prices may not be high
1,2 enough or firm enough to cause QEs to be built?
13 A. Quite simply, that PURPA never was intended to
14 subsidize QFs. If the prices that utilities can buy power
15 for in markets are too Iow to support a parti-cular QE or
16 type of QF, it is entirely conslstent with PURPA that the
L7 QF is not buj-It. Regarding the firmness of prices, it
18 simply is not the case that long-term firm prlces are
L9 required in order to get QEs or, for aI1 that, non-QF
20 merchant capacity bui1t. A "bankabfe" contract makes it
2L easier and cheaper to get high leverage project finance.
22 However, nothing in PURPA mandates that customers should
23 shoulder the price risks that make cheap financing
24 available, especially since the reduced financing cost is
25 not flowed through to them in lower power costs.
HTERONYMUS, Dr 99
Idaho Power Company
l- 0. Are there reasons why it might be preferable
2 to use the second type of market pricing, the RFP, or
3 action method?
4 A. The primary virtue of this type of procurement
5 is that it can be tailored to acquire the types of capacity
6 that the particular utility needs. Such procurements can,
7 and have, given weight to the various factors that FERC
8 said from the beginning of PURPA should be taken into
9 account, such as firmness, dispatchability, fuels
10 dj-versity, and so forth. I recognize that a procurement
11 that seeks to weight these various non-price factors
12 quickly becomes complex and arguably somewhat arbitrary,
13 but there is now a considerable body of experience that
L4 could guide the development of such a methodology.
15 Erom a QF's perspective, a virtue of the RFP/auction
16 process is that the QF sets its own bid level.
1,7 Necessarily, the price set in the REP is commercially
18 acceptable, at l-east to the winners. By the nature of the
19 procurement, QFs that can or will only accept higher prices
20 wiII not be selected. fmportantly, by limiting the
2l quantity procured to the amount that the utility actually
22 needs, the process shields ratepayers from the risk of
23 paying what may be excessive amounts for power that is not
24 needed and cannot be resol-d for the contract costs.
25
HIERONYMUS, DI 100
Idaho Power Company
1 The RFP/auction method ls best applied if there is a
2 need for new power supplies. White it might be possible to
3 have an energy-onIy auction when no capacity is needed,
4 this is not likely to attract the entry of new suppliers.
5 My understanding is that at least some Idaho utilities do
6 not presently need new capacity beyond that already on-line
1 or under construction and that lPC is also long energy
B under normaL water conditions in almost all time periods.
9 Q. You have shown support for market-based
l-O methods of setting avoided cost. Are there reasons why
11 Idaho might validly chose an admj-nistrative method?
1,2 A. I have suggested that simply paying market
13 prices might not be acceptable to FERC and that the
L4 RFP/auction method is of questionable applicability in the
l-5 face of excess capacity and energy. I also recognize that
1-6 movement to market-based methods would be a very large
L7 change from ldaho's current practices. In my experience,
l-B regulation usually changes on a more evolutionary basis.
19 Hence, while I believe that the market solutions merit
20 serious consideration in ldaho, I observe that this is not
2t the current expectation as is shown by the fact that this
22 proceeding is focused on improving Idaho's avoided cost
23 calculation methods using methods other than market price
24 discovery.
25
HIERONYMUS, DI ]-O].
Idaho Power Company
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VI. SUGGESIIOITS COITCERNIIIG AVOIDED COST PRICIIIG
BAIIED ON IDMISISTRATIVE METEODS
O. Assuming that the Idaho Commission wishes
continue to set avoided costs administratively, what
suggestions to you have?
A. My first suggestion is that it should rely on
the IRP-type of calculation. I make the following
suggesti-ons for the how the IRP-type of avoided cost
calculation could be conducted:
l-. Avoided cost calculations should
QF, not
to
be
on thebased
costs
on
of
the specific characteristics of the
a proxy unit.
2.Set schedules should be made available
only for smal1 units. Avoided costs for these schedules
for smaller resources should be based on IRP anal-yses for
generic versions of that type of resources. At a minj-mum,
Idaho should have generi-c avoided costs for wind,
photovoltaic solar, cogeneration (and other baseload fueled
projects), and irrigation-based hydro.
3. Calculations of energy value should be
based on the latest available information, not frozen for
extended periods. Offering prj.ces based on non-current
forecasts will cauae either a flood or dearth of offers
depending on the direction of changes.
4. The model used to forecast energy
prices should be updated as appropriate to refl-ect the
HIERONYMUS, DI LOz
fdaho Power Company
L amount of QF capacity that is in process. Additions of QF
2 capacity that are must-take or inframarginal, as is the
3 case for the types of QEs being offered in ldaho, displace
4 higher cost units and hence result in lower system marginal
5 costs. Including previously contracted QFs in the model-
6 used to predict avoided energy costs makes avoided cost
7 calculation more current and accurate and has the salutary
8 effect that if a glut of QFs materializes due to too
9 favorable avoided cost offers, the resultant drop in prices
1-0 shoul-d help to moderate the glut.
11 5. For quite large increments of capacity
L2 (either individual projects or aggregates of projects), the
l-3 effect of the resource on marginal costs and the need for
74 capacity should be taken into account. This suqgests an
15 IRP-type of "with and without" simulation rather than the
1-6 static "without" simulation to determine energy costs that
L7 is adequate and appropriate for sma1l QEs.
1-8 6. If Idaho retains long-term or even
19 intermediate-term contracts with predetermined prices, it
20 is important that customers not take on price and
2L marketabitity risks for power that is not economj-calIy or
22 operationally useful on the utility's system. PURPA does
23 not require that off-system sales revenues be factored into
24 avoided costs and 1t is improper for customers to shoulder
25 such risks for power that does not benefit them.
HIERONYMUS, DI 103
fdaho Power Company
L 7. The capacity cost component of avoided
2 cost should be based on the cost of the resource with the
3 lowest net cost, net cost being computed based on its fixed
4 costs offset for net contributions earned from provj-ding
5 energy and anci-Ilary services, if any. Normally the
6 correct unit will be a simple cycle combustion turbine,
7 though in some circumstances it has been shown to be a
I different type of unit.36
9 B. The appropriate maximum project size at
10 which fixed schedules are offered to QFs (presently, 1-00 kW
11 for wind and solar and 10 aMlrl for other types of QFs)
L2 should be kept 1ow, especially if ldaho continues to use a
13 single SAR-based schedule for small QFs. Conversely, it
1"4 may be reasonable to somewhat relax the size limit if the
15 single SAR schedule is replaced by multiple, IRP-based
16 generic schedules for the individual types of QFs.
1-7
" A. explained previously, the cheapest form of capacity (other
than, perhaps, some forms of demand response) is a simple cycle peaker.
However, other units may be cheaper forms of capacity if their highercost is more than off-set by their higher value i-n produclng energy andancillary services. The three northeastern RTOs, which have capacitymarkets, derive the starting point for determining a capacity price
based on the "net cost of new entry. " Thj-s is the annual fixed cost ofthe unit, minus the difference between the revenues it would earn forselling energy and ancillary services and the variable cost ofproviding them. At times, this revenue offset has been large enoughfor combj-ned cycle units that they have been the new entry, unit, sincetheir net cost j.s below the net cost of the peaker. I also notedprevi-ously that capacity costs used for avoided cost purposes sometimesdo not offset costs with energy and ancillary services value. This isconceptually wronq, but may be acceptable factually where and when
peakers earn negligible margins. Conversely, where o1d and inefficientunits are marginal much of the time, in New York City for example, theoffsets are quite important.
HIERONYMUS, DI 104
Idaho Power Company
L 9. Al-I calculations need to take into
2 account whether the utility needs, or even can absorb the
3 energy and capacity from the QF. If QE procurement cannot
4 be cut off entirely when no resources are needed, avoided
5 costs should reflect the lack of need. At a minimum, the
6 capacity value component of avoided cost should be adjusted
7 to reflect a low to zero capacity value for unneeded
8 capacity.
9 Q. In your discussion of the Lessons learned from
10 PURPA experience, you stated that the most important source
11 of excess costs being imposed on utility customers came
12 from Iarge amounts of power purchased under long-term
13 contracts at prices that were fixed at levels that turned
L4 out to substantially exceed avoided costs. Do you have any
l-5 recommendation concerning contract length?
16 A. Yes. Long-term contracts with prices,
L'l particularly energy prices, set for long durations should
18 be avoided. PURPA does not require that contracts of any
1-9 particular term length be offered. However, if long-term
20 contracts are offered, the QF gets to choose whether it
2L wants to be paid avoided costs computed at the time of the
22 contract or avoided costs computed at the time of delivery.
23 PURPA and the FERC regulations also are silent on
24 the type of price offer that must be made at the time of
25 contracting. The long-term offer, if made, presumably
HIERONYMUS, DI 105
Idaho Power Company
1 could be either a fixed schedule of prices or a formula
2 rate (as FERC suggested in the Avoided Cost NOPR). A
3 formula rate couId, for example, be wholly or partially
4 indexed to gas prices. fndeed, my understanding is that
5 the current Idaho avoided cost rates for fueled projects
6 are of this nature. CIearIy, a formula rate linked to the
7 cost of the power purchases or fuel that is actually
8 avoided due to QE purchases is both more appropriate under
9 PURPA and less risky for customers.
10 O. QF developers contend that long-term contracts
1-1 are essential since without assured revenues, the projects
t2 cannot be financed. ff long-term fixed prices are not
13 offered, does this mean that no one will build QEs in
14 rdaho?
15 A. Not necessarily. It is not actually true that
16 non-utility generation, including QFs, wlII not be built
L7 without long-term contracts with fixed prices. There are
18 numerous examples of EWGs that are financed and built
19 without such contracts. Indeed, some are being built in
20 the exempt regions without bilateral contract support.
21- What is actually complained of by developers is that the
22 lack of such contracts raises fj-nancing costs. A secure
23 and predictable revenue stream aLlows new facilities to be
24 project financed with high leverage and 1ow debt costs. In
25 effect, the utility signing such a contract is absorbing
HIERONYMUS, DI ].05
Idaho Power Company
1 the financial risks of the project by guaranteeing a
2 revenue stream that may greatly exceed actual value or, at
3 a minimurn, is substantially more certain than the
4 fluctuating value of energy in today's volatile power
5 markets. Project risk is thus shifted from the developer
6 and lenders to the utility and its shareholders and
7 ratepayers. For QFs (and distinct from EViGs), the risk is
8 shifted entirely to ratepayers since, by 1aw, prudently
9 incurred costs of PURPA power must be passed through in
l-0 rates.
11 PURPA does not requj-re, and I can think of no
L2 justification for, Idaho utilities' customers absorbing the
l-3 risks that lenders to QEs arguably will not. The risk that
L4 long-term fixed prices may prove to have been substantially
15 mj-s-forcast is the greatest problem with PURPA
L6 implementation. Long-term contracts at predetermined
L7 prices are the main reason why many contracts slgned in the
18 1980s resulted in windfall gains for developers and
19 excessive cost for ratepayers. FueI prl-ces had been
20 expected to continue to escalate, but actually declined. I
21 note that ldaho, at the time, adjusted its contract terms
22 to reflect this lesson. The contract term for Idaho
23 standard offers was reduced from 35 to 20 years in 1987 to
24 reduce this forecast uncertainty. It subsequently was
25 reduced to 5 years. In 2002, the maximum contract term was
HIERONYMUS, DI 1.07
Idaho Power Company
1 increased back to 20 years, notwithstanding that then-
2 recent experience demonstrated the huge risks involved j-n
3 setting prices based on forecasts of fuels prices over long
4 periods.3T
5 As I have discussed, the perception in the 1980s
6 that contract prices were well above market and like1y to
7 be reduced as regulators lowered fuels forecasts
B contributed to a gold rush of unneeded power, exacerbating
9 the cost impacts on mis-forecastinq. A similar situation
10 appears to be occurring now, as qas prices forecasts have
11- been lowered and then lowered again and again as
12 forecasters have come to better understand the impact of
L3 new technology for recovering shale gas on gas supplies and
1,4 prices.
15 O. Are there other reasons why Idaho is
16 vulnerable today to too-high prices for QF power?
L7 A. Yes. For certain types of resources, some
18 areas of the country are much better than others. Wind,
L9 so1ar, and sma1l hydro are obvious examples. To focus on
37 rdaho avoided cost rates for non-fueled projects that were ineffect just prior to Decision 29L24 Ln 2002 were assumed to increase by
6 percent per year from a base of 95.23lrunBTU. In that decision, the
forecast was reduced to an escalation rate of 2.6 percent from a baseof S3.75lmmBTU. Obviously, such a difference has an enbrmous impact.
The fuel- cost of the 7100 BTU heat rate unit adopted in that proceeding
for the proxy unit would escalate to $66.4 per MWh in 10 years based on
the then-preexisting assumptions versus $33.4/Mwh under the new
assumptj-ons. After 20 yeaxs, the fuel costs would be $118.4/MWh under
the prior assumptions and $44.8/MWh under the assumptions adopted in2002. Current fuels priees and forecasts suggest that even the lower
of these forecasts was too high.
HIERONYMUS, Dr 108
Idaho Power Company
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wind, the best wind regimes are primarily in the Pacific
Northwest and northern Midwest (and to a lesser degree, the
northeast) and in areas like Oklahoma and the Texas
panhandle. An examination of installed wind power
demonstrates that Idaho has in the past been only one of
several good l-ocations. However, most of the states
mentioned as good wind regimes, outside of the Pacific
Northwest, are now exempt from PURPA. Developers seeking
PURPA contracts have much narrower markets. The exemption
of utilities 1n previously attractive markets may be one
reason for the surge of contract reguests in fdaho in 2010.
O. If the avoided cost rates and contract terms
offered in Idaho are made less attractive, what will
happen?
A. This depends partly on what happens in other
states. QF developers today are essentially balance sheets
looking fo:i profitable investments, wherever they can be
found. If fdaho offers lower prices and/or less attractive
contract terms than other states, QE developers may choose
to build in those states. This is not necessarily a bad
thing. A state that pays too much for QF power will not
only overpay, but also attract unneeded capacity. This is
the strong lesson learned from the New York and California
experiences in particular. The large amount of QF power
H]ERONYMUS, DI 1-09
Idaho Power Company
1 tendered to IPC suggests that it may be a recent lesson for
2 Idaho.
3 Q. Does eliminating long-term fixed prices only
4 protect customers?
5 A. No. As events unfolded in the past, fuel
6 costs were much lower than the forecast costs embedded in
7 fixed contract prices, so that contracts were very
8 profitable to developers who bought cheap gas and sold
9 power at prices that had been set assuming expensive gas.
10 However, had events been different, with gas prices well
l-l- above the forecasts fixed into contracts, the roles would
L2 have been reversed. The cogenerators who sold at fixed
13 prices would have had to buy gas at prices well in excess
14 of the prices implicit in the QF energy price. Such QEs
15 easily could have lost money on every k['Ih generated and
l-6 would have soon been bankrupt.
L7 a. What do you suggest is the appropriate way to
1"8 treat contract length and firmness?
19 A. Contract lengths should be quite llmited if
20 fixed prices are used. One possible Iimit is the length of
2L time for whj-ch Idaho utilities can hedge the value of the
22 power that they purchase by engaging in off-setting
23 bilateral sales contracts elsewhere. This would be
24 particularly appropriate j-f, contrary to what IPC is
25 seeking to achleve with its proposal, the Idaho ut.ilities
HIERONYMUS, DI 1].0
Idaho Power Company
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are required to contract for QF power that they do not need
and will have to sell into interchange markets during much
of the contract term with customers taking the price risk.
A still short, but somewhat longer, contract term could be
appropriate for QEs that actually can be absorbed by the
host utility's load.
Contract length can be limit,ed directly, or by
limiting the period of time for which prlces are firm. If
the firm period is less than contract length, the contract
can specify how prices will be reset in the future.
O. Is it the case that short contracts create
stranded asset rj-sks for developers, in that the developer
may not have a customer to whom power can be sold once the
contract is over?
A.That is a theoretical risk, and may not even
be merely theoretical for EWGs that do not have access to
competitive markets. However, so long as ldaho utilities
are not exempt from PURPA Section 210 obligati-ons, their
obligation to buy the output of QFs remains. A QF with an
expiring contract is entitled to a new contract from its
interconnected utility.
It is possible that changed circumstances or federal
1aw may cause the Idaho utilities to become exempt from
PURPA Section 210 responsibilities sometime in the future.
However, under PURPA as modified by EPAct, exempti-on
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Idaho Power Company
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reguires satisfying FERC that QFs wiII have access to a
competitive market into which they can sell power.
Exemptions therefore will not be granted if there is any
material risk that QF assets will be stranded.
a.Are you as concerned about fixing long-term
prices for capacity as you are for energy?
A.No. Technological change and changes in
financing costs can create a mismatch between avoided
capacity cost estimates and outcomes.38 However, building
new, Iong-lived utility plant always entails these risks.
Moreover, the variability in outcomes for capacity cost and
value are considerably less than for energy.
o.If the Idaho Commission decides that it wants
to require long-term QE contracts with terms set at the
time of signing, what terms can be used to limit risks to
the utilitles' customers?
A. Fixing terms at the time of signing does not
necessarily require fixing prices. Other than provisions
calling for periodic resetting of prices, the obvious
alternative for reducing customer risk is price indexation.
One option is to index prices to power prices in adjacent
markets. I have discussed instances where this is done.
38 The previous footnote illustrated the change in Idaho avoidedcost parameters relating to fuels markets in 2002. In comparison,fixed costs relating to capacity were little changed, with the capitalcost of the combined cycle unit declining somewhat in real terms andthe fixed operations and maintenance rate increasing somewhat.
HIERONYMUS, DI 7L2
Idaho Power Company
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An alternative which is only modestly less useful- is to
index energy prices at least partly to natural gas prices.
Prices in Northwest energy markets are, at least much of
the time, based on prices into Cal-ifornia. In turn,
California prices are set based on the cost of gas most of
the time, other than durJ-ng the spring run-off affecting
Northwest and California hydroelectric generation. For
this reason, indexing contract energy costs to actual gas
pri-ces reasonably assures that contract prices wil-I not
diverge greatly from the value of power in the marketplace
and the prices at which fdaho utilities buy and sell power
in northwestern markets, at least in periods other than
times of peak water fl-ow.
Eor the gas-fired cogenerators that historically
were the bulk of QFs, indexed prices also reduced rather
than increased risk since fuel-indexed rates caused energy
payments to track their fuel- costs, locking in capacity-
related margins that pay most of construction-related
costs. However, j-ndexation does not protect margins for
the non-gas fired generators that are the primary source of
recent QFs in ldaho.
a.Do you have any concluding comment on how
PURPA avoided costs should be set and contracts formulated?
A.Yes. Consistency with the letter and intent
of PURPA Section 210 requires state implementations with
HIERONYMUS, DI 1L3
Idaho Power Company
1- two, and only two consequences: assuring that QFs are not
2 discriminated against, and protecti-ng customers by limiting
3 payments to be no higher than the utility's avoided cost.
4 PURPA was not, and is not, intended to guarantee that QFs
5 will be profitable, or even that they will be built.
6 It is likely that resetting prices to reflect lower
7 fuel price escalation expectations and the existence of
8 excess capacity in the state and reducing the scope of
9 price guarantees will result in lowe,r amounts of QF power
10 being offered in Idaho than has been offered in recent
l-l- years. This is an appropriate outcome and is fu11y
L2 consi-stent with the letter and intent of PURPA. If Idaho
13 determines that it needs more renewable generation than
t4 PURPA produces, there are other policy tools that can be
15 used to cause renewable generation to be constructed,
16 including, for example, set-aside procurements limited to
71 renewables such as were approved in the past year for
18 CaLifornia.
l-9 a. Does this complete your testimony at this
20 time?
21- A. Yes, it does.
22
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HIERONYMUS, DT LLA
Idaho Power Company
BEFORE THE
IDAHO PUBLIG UTILITIES COMMISSION
CASE NO. GNR.E.I1.O3
IDAHO POWER COMPANY
HIERONYMUS, DI
TESTIMONY
EXHIBIT NO.6
WILLIAM H. HIERONYMUS
Resume of William H. Hieronymus
Ph.D. Economics
Univesity of Midligan
M.A. Economics
University of Michigan
B.A. Social Sciences
Univecig of lora
\Mlliam Hieronymus has consulted extensively to managements of elec{rlcity and gas companies, their
counsel, regulators, and policymakers. His principal areas of ooncentration are the eoonomics, structure
and regulation of netvuork utilities and associated management, policy, and regulatory issues. Dr.
Hieronymus has spent the last twenty years working on the restruc{uring and privatization of utility
systems in the U.S. and intemationally. ln this context he has assisted the managements of energy
companies on corporate and regulatory strategy, particularly relating to asset acquisition and divestiture.
He has testified extensively on regulatory policy issues and on ma*et porver issues related to mergers
and acquisitions. ln his thirty-odd years of consufting to this sector, he also has performed a number of
more specific tunctional tasks, including analyzing potential investments; assisting in negotiation of power
contracts, tarifi formation, demand forecasting, and fuels market forecasting. Dr. Hieronymus has
testified ftequenUy on behalf of energy sector clients before regulatory bodies, federal courts, arbttrators
and legislative bodies in the United States, the United Kingdom and Australia. He has contributed to
numerous proiects, induding the following:
ELECTRICITY SECTOR STRUCTURE, REGULATION, AND
REIIITED MANAGEMENT AND PIIINNING ISSUES
U.S. Market Restructurin g Assignments
o Dr. Hieronymus serves as an advisor to the senior executives of eleclric utilities on restructuring and
related regulatory issues, and he has worked with senior management in developing strategies for
shaping and adapting to the emerging competitive market in electicity. Related to some of these
assignments, he has testified before state agencies on regulatory policies and on contac{ and asset
valuation.
Exhibil No. 6
Case No. GNR-E-11-03
W Hieronymus, IPC
Page 1 of8
Resume of William H. Hieronymus
For utilities seeking merger approval, Dr. Hieronymus has prepared and testified to market po\fler
analyses at FERC and before state commissions. He also has assisted in discussions with the
Antitrust Division of the Department of Justice and in responding to information requests. The
mergerc on ufiich Dr. Hieronymus has testified include both electricity mergers and combination
mergers involving electdcity and gas companies. Among the major mergers on wtrich he has
testifted are Duk+Progress, DukeCinergy, NSTAR-Northeast Utilities, Sempra (Enova and Pacific
Enterprises), Xcel (New Century Energy and Northem States Povtrer), Exelon (Commonweatth
Edison and Philadelphia Electric), AEP (American Electric Power and Central and Southwest),
Dynegy-lllinois Porer, Con Edison-Orange and Rockland, Dominion-Consolidated Natural Gas,
NiSource-Columbia Energy, E-oePouveGen/LG&E and NYSEGRG&E, lberdrola-Energy East,
Texas Energy Futures-TXU, ExelorrNRG, GDF/Suez and FirstLight and MacQuarie-Puget Sound.
He also submitted testimony in mergers that were terminated, usually for unrelated reasons,
including EEG (Exelon and PSEG), Constellation-FPl Energy, Entergy-Florida Power and Light,
Northem States Power and Wisconsin Energy, KCP&L and Utilicorp and Consolidated Edison-
Northeast Utilities. Testimony on similar topics has been filed for a number of smaller utility mergers
and for nunierous asset acquisitions. Dr Hieronymus has also assisted numerous clients in the pre-
merger screening of potential acquisitions and merger partners.
For utilities seeking to establish or extend market rate authority, Dr. Hieronymus has provided scores
of analyses conceming market power in support of submissions under Sedions 205 and/or 206 of
the Federal Power Act.
For utilities and power pools engaged in restructuring activities, he has assisted in examining various
facets of proposed reforms. Such analysis has included features of the proposals afiecting market
efiiciency and revenue adequacy and those that have potential consequenoes for market pourer.
l/Vltere relevant, the analysis also has examined the effects of altemative reforms on the market
performance, and achievement of ttre client's objectives. ln some cases, these analyses have led to
testimony and/or participation in stakeholder processes.
For generators and marketers, Dr. Hieronymus has testified extensively in the regulatory
proceedings conceming the electricity crisis in the WECC that occuned during the period May 2000
through May 2001. His testimony concemed, inter alia, the economics of long term contracts
entered into during that period the behavior of market participants during the crisis period and the
nexus between purportedly dysfunctional spot markets and forward contracts. He also provided
testimony and other regulatory support in dockets concerned with economic and physical
withholding, partnership arrangements and bidding and scheduling practices potentially in violation of
the ISO tarifi.
For the New England Power Pool (NEPOOL), Dr. Hieronymus examined the issue of market porrer
in connection with NEPOOL's movement to market-based pricing for energy, capacity, and ancillary
services. He also assisted the New England utilities in preparing their market power mitigation
proposal. The main results of his analysis were incorporated in NEPOOL's market porrer fiting
before FERC and in lSGNew England's market power mitigation rules.
For a coalition of independent generators, he provided affdavits advising FERC on changes to the
rules under which the northeastem U.S. porrer pools operate.
For both utilities and generators he has testified on a number of occasions on market mitigation rules
for the New York City load pocket and their relationship to policy goals such as market-based entry.
Exhibit No. 6
Case No. GNR-E-I1-03
W. Hieronymus,lPC
Page 2 of 8
Resume of William H. Hieronymus
Valuation of Utility Assets in North America
e Dr. Hieronymus has testified in state securitization and stranded cost quantification proceedings,
primarily in forecasting the level of market prices that should be used in assessing the tuture
revenues and the operating contribution eamed by the owner of utility assets in energy and capacity
markets. The market price analyses are tailored to the specific features of the market in which a
utility will operate and rellect tsansmission-constrained trading over a wide geographic area. He also
has testified in rebuttal to other parties'testimony conceming stranded costs, and has assisted
companies in intemal stranded cpst and asset valuation studies.
o He was the primary valuation witness on behalf of a westem utility in an ar0itration proceeding
conceming the value of a combined cycle plant coming ofi lease that the utility wished to purchase.
o He assisted a bidder in determining the commercial terms of plant purchase offers as well as
assisting clients in assessing the regulatory feasibility of potential acquisitions and mergers.
r He has testified conceming the value of terminated long term contracts in connection with confact
defaults by bankrupt power marketers and merchant generators.
. ln connec{ion with the Westem U.S. long term contracts proceeding, he testified with respecl to
benchmarking of contract and to the relationship between market prices and long run marginal
costs of new generation.
Other U.S. Utility Engagements
r ln a recent arbitration proceeding, Dr. Hieronymus testified wilh respect to confact terms relating to
security provisions for long repaying font+nd loaded confacrt payments.
o Dr. Hieronymus has contibuted to the development of several benchmarking analyses for U.S.
utlities. These have been used in work with clients to develop regulatory proposals, set cost
reduction targets, restructure intemal operations, and assess merger savings.
r Dr. Hieronymus was a co-developer of a market simulation package tailored to region-specific
applications. He and other senior personnel have conducied numerous multi-day training sessions
using the package to help utility clients in educating management regarding the consequences of
wholesale and retail deregulation and in developing the skills necessary to succeed in this
environment.
e He has made numerous prcsentations to U.S. utility managements regarding overseas electricity
systems and market reforms.
. ln connection with nuclear generating plants nearing completion, he has testified in Pennsylvania,
Louisiana, Arizona, lllinois, Missouri, New York, Texas, Arkansas, New Mexico, and before the
Federal Energy Regulatory Commission regarding plant-irservice rate cases on the issues of
equitable and economically efficient tredment of plant costs for tariff-setting purpces, reguHory
treatment of new plants in otherludsdictions, the prudence of past sy:tem planning decisions and
assumptions, performance incentives, and the life-cycle costs and beneliE of the units. ln these and
other utility regulatory proceedings, Dr. Hieronymus and his colleagues have provided extensive
support to counsel, including preparatbn of intenogatories, cross-examinalion support, and
assistance in writing briefs.
Exhibit No. 6
Case No. GNR-E-11-03
W. Hieronymus,lPC
Page 3 of 8
Resume of William H. HieronYmus
. On behatf of utilities in the states of Michigan, Massacfrusets, New York, Maine, lndiana,
Pennsylvania, New Hampshirc, and lllinois, hs has submitted testimony in regulatory proceedings on
the economics of completing nudear generating plants that were tfien under construction. His
testimony has covered the likely cost of plant completion; forecasts of operating performance; and
extensive analyses of the impacts of completion, deferral, and cancellation upon ratepayers and
shareholderc. For the senior managements and boards of utitities engaged in nuclear plant
construc{ion, Dr. Hieronymus has performed a number of highly confidential assignments to support
strategic decisions conceming the continuance of construction.
r For an eastem Pennsylvania utility that suffered a nuclear plant shutdown due to NRC sanctions
relating to plant management, he filed testimony regarding the ertent to wtrich replacement power
cost exceeded the costs that would have occuned but for the shutdown.
. For a major Midwestem utility, Dr. Hieronymus headed a team that assisted senior management in
devising its strategic plans, including examination of such issues as plant refurbishment/life
extension strategies, impacts of increased competition, and available diversification opportunities.
o On behalf of two West Coast utilities, Dr. Hieronymus testified in a needs certification hearing for a
major coal-fired generation complex conceming the economics of the facility relative to competing
sourqes of power, particularly unconventional sources and demand reductions.
. For a large westem combination utility, he participated in a major 1&month effort to provide the client
with an integrated planning and rate case management system.
r For two Midwestem utilities, Dr. Hieronymus prepared an analysis of intervenor-proposed
modifications to the utilities' resource plans. He then testified on their behalf before a legislative
committee.
U.K. Assignments (1 988-, 994)
o Following promulgation of the white paper that established the general frameworft for privatization of
the electricig industry in the United Kingdom, Dr. Hieronymus participated extensively in the task
forces charged with developing the new markel system and regulatory regime. His work on behalf of
the Electricity Council and the twelve regional distribution and retail supply companies focused on
the proposed regulatory regime, including the price cap and regulatory formulas, and distribution and
transmission use of system tariffs. He was an ac{ive participant in industryAovernment task forces
charged with creating the legislation, regulatory framework, initial contracts, and rules of the pooling
and setlements system. He also assisted the regional companies in the valuation of initial contract
offers ftom the generators, including supporting their successful refusal to contract for the proposed
nuclear power plants that subsequently were canceled as being non-commercial.
. During the preparation for privatization, Dr. Hieronymus assisted several individual U.K electricity
companies in understanding the evolving system, in developing use of system tariffs, and in
enhancing commercial capabilities in power purdrasing and contacting. He continued to advise a
number of clients, including regional companies, power developers, large industrial customers, and
financia! institutions on the U.K. porver system for a number of years after privatization.
Exhibit No. 6
Case No. GNR-E-11-03
W. Hieronymus, IPG
Page 4 of 8
Resume of William H. Hleronymus
. Dr. Hieronymus assisted four of the regional electricity companies in negotiating equity ownership
positions and devdopang the power purchase contracls lor a 1,825 megawatt combined cycle gas
stration. He also assisted clients in evaluating other potential generating investments induding
cogeneration and non-conventional resouroes.
. Dr. Hieronymus also has consulted on the separate reorganization and privatization of the Scottish
elecfiicity sector. Part of his role in that privatization included advising the larger of the two Scottish
companies and, through it, ihe Secretiary of State on all phases of the resfrtrduring and privatization,
including the drafting of regulations, asset valuation, and company strategy.
o He assisted one of lhe Regional Electricity Gompanies in England and Wales in the 1993 through
1995 regulatory proceedings that reset the price caps for its retailing and distribution businesges.
lncluded in this assignment was consideration of such pdicy issues as incentives for the economic
purchasing of power, the scope of price control, and the use of comparisons among companies as a
basis for pdce regulation. Dr. Hieronyrnus's model for determining network re{Urt ishmant needs was
used by the regulator in determining revenue allowanccs for capital investments.
e He assisted one of the Regional Electricity Companies in its defense against a hostile takeover,
including preparation of its submission to the Cabinet Minister wfro had the responsibility for
determining whether the merger should be refened to the competition authority.
Assignments Outside the U.S. and U.K.
r Dr. Hieronymus testified before the federal court of Australia conceming the market pouar
implications of acquisition of a share of a large coal'fircd generating facility by a large retail and
distribution company.
o Dr. Hieronymus assisted a large stateowned Eurcpean electicity oompany in evaluating the impacts
of the EU directive on electricity lhal intar alia required retail access and competitive markets for
generation. The assignment induded advice on the organizational solution to elements of the
direclive rcquiring a separato transmission system operator and the business need to create a
competitive marketing fu nction.
r For the European Bank for Reconsfuction and Development, he performed analyses of least-cost
pouer options and evaluated the retum on a major investnent that the Bank was considering fur a
partially completed nudear plant in Slovaka. Part of this assignment involved developing a forecast
of electdcity prices, both in Eastem Europe and for potential exports to the West.
o For the OECD he performed a study of energy subsidies worldwide and the impact of subsidy
elimination on the environment, particularly on greenhouse gases.
. For the Magyar Mllamos Muvek Troszt, the elec{ricity company of Hungary, Dr. Hieronymus
developed a contrac't framarork to link the operations of the difierent entities of an elecfricity seclor
in the process of moving ftorn a centralized command- and-control system to a decentralized,
corporatized system.
r For lberdrola, the largest investor-owned Spanish electricity company, he assisted in development of
their proposal for a fundamental reorganization of the electricity sec{or, its means of compensating
generation and distribution companies, its regulation, and the phasing out of subsidies. He also has
assisted the company in evaluating generation expansion options and in valuing ofierc for imported
power.
Exhibit No. 6
Case No. GNR-E-11-03
W. Hieronymus,IPC
Page 5 of 8
Resume of William H. HieronYmus
r Dr. Hieronymus contributed extensively to a proiectforthe Ukrainian Electici$ Minisfy, the goal of
wtrich was to reorganize the Ukrainian elec'tricity sector and prepare it for transfer to the private
sector and the atraction of foreign capitral. The proposed reorganization is based on regional electric
pou,er companies, linked by a unified central market, with market-based prices for electricity.
r At the request of the Ministry of Power of the USSR, Dr. Hieronymus participated in the creation of a
seminar on electricity restructuring and privatization. The seminar was given for 200 invited
Ministerial staff and senior managers for the USSR power system. His specific role was to introduce
the requirements and methods of fivatization. Subsequent to the breakup of the Soviet Union, Dr.
Hieronymus continued to advise both the Russian energy and power ministry and the govemment-
owned generation and transmission company on restruc{uring and market development issues.
. On behalf of a large continental electricig oompany, Dr. Hieronymus analyzed the proposed
direstives from the European Commission on gas and electricity transit (open access regimes) and
on lhe intemal market for electricity. The purpose of this assignment was to forecast likely
developments in the structure and regulation of the electricig sector in the common market and to
assist the client in understanding their implications.
o For the electric utility company of the Republic of lreland, he assessed the likely economic benefit of
building an interconnector between Eire and Wales for the sharing of reserves and the interchange
of power.
o For a task force representing the Treasury, electricity generating, and eledricity distribution
industies in New Zealand, Dr. Hieronymus undertook an analysis of industry strucfure and
regulatory altematives for achieving the economically efficient generation of electricity. The analysis
explored how the industy likely would operate under altemative regimes and their implications for
asset valuation, electicity pricing, competition, and regulatory requirements.
TARIFF DESIGN METHODOLOGIES
AND POTICY ISSUES
r Dr. Hieronymus participated in a series of studies for the National Grid Company of the United
Kingdom and for ScottishPower on appropriate pricing methodologies for transmission, including
incentives for efficient investment and location decisions.
r For a U.S. utility client, he directed an analysis of timedifferentiated costs based on acc,ounting
concepts. The study required selec{ion of rating periods and allocation of costs to time periods and
within time periods to rate classes.
o For EPRI, Dr. Hieronymus directed a study that examined the effects of time-of-day rates on the
level and pattem of residential electricity consumption.
r For the EPRhNARUC Rate Design Study, he developed a methodology fur designing optimum cost-
tracking block rate struclures.
o On behalf of a group of cogenerators, Dr. Hieronymus liled testimony before the Energy Select
Committee of the UK Parliament on the efiects of prices on cogeneration development.
Exhibit No. 6
Case No. GNR-E-11-03
W Hieronymus, IPC
Page 6 of I
Resume of William H. Hieronymus
r For the Edison Electric lnstitute (EEl), he prepared a stiatement of the industry's position on proposed
federal guidelines regarding fuel adjustment clauses. He also assisted EEI in responding to the U.S.
Departrnent of Energy (DOE) guidelines on cost-of-service standards.
. For private utility clients, Dr. Hieronymus assisted in the preparation both of their comments on draft
FERC regulations and of their compliance plans for PURPA Section 133.
o For a state utilities commission, Dr. Hieronyrnus assessed lts utililies'existing automatic adjustsnent
clauses to dctemine their compliance with PURPA and recommended modifications.
o For DOE, he developed an analysis of automatic adjustment clauses cunenty employed by elecfic
utilities. The focus of this analysis was on efEciency incentive effects.
r For the commissioners of a public utility commission, Dr. Hieronymus assisted in preparation of
briefing pepers, lines of guestioning, and proposed findings of fact in a generic rate design
proceeding.
SALES FORECASTING METHODOLOGIES
FOR GAS AND ELECTRIC UTILITIES
o For the White House SubCabinet Task Force on the future of the elec'trio utility indusfy, Dr.
Hieronymus co-directed a major analysis of least-cost planning studies" and 1otrgrorlfi energy
ftrtures." That analysis was he sole demanGside study commissioned by the task force, and it
formed a basis for the task force's @ndusions conceming the need fur new f;acilities and the relative
roles of new construction and cr.rstomer side'of-the-meter programs in utility planning.
o For a large eastern utility, Dr. Hieronymus developed a load fiorecasting model designed to interface
with the utility's revenue forecasting system-planning functions. The model forecasts detailed
monthly sales and seasonal peaks for a lG.year period.
r For DOE, hE directed development of an independent needs assessment model for use by state
public utility commissions. This major study developed the capabilities required for independent
forecasting by state commissions and provided a foracasting model for their interim use.
r For state regulatory commissions, Dr. Hieronymus has consulted in the development of servioe area-
level forecasUng models of electric utility companies.
r For EPRI, he authored a study of electricity demand and load forecasting models. The study
surveyed state-of-the-art models of electicity demand and subjected the most promising models to
empirical testing to determine their potential for use in longterm forecasting.
r For a Midwestem elec.tric utili$, he provided consulting assistance in improving the dient's load
forecast, and testified in defense of the revised forecasting models.
r For an East Coast gas uflity, Dr. Hieronynus testified with respect to sales forecasts and provided
consulting assistance in improving the models used to forecast residential and commercial sales.
Exhibit No.6
Case No. GNR-E-I1-03
W. Hieronymus, IPC
Page 7 of8
Resume of William H. Hieronymus
OTHER STUDIES PERTAINING TO
REGULITTED AND ENERGY COMPANTES
ln a number of antitrust and regulatory matters, Dr. Hieronymus has performed analyses and
litigation support tasks. These cases have included Sherman Acl Section 1 and 2 allegations,
contract negotiations, generic rate hearings, ITC hearings, and a major asset valuation suit. ln a
major antitust case, he testified with respect to the demand for business telecommunications
services and the impact of various practices on demand and on the market share of a new enhant.
For a major elecffical equipment vendor, Dr. Hieronymus testified on damages with respecl to
alleged defects and associated fiaud and vuananty claims. ln connection wilh mergers for which he
is the market power expert, Dr. Hieronymus assists clients in Hart-Scott-Rodino investigations by the
Antitrust Division of the U.S. Departnent of Justice and the Federal Trade Commission. ln an
arbitration case, he teslified as to changed circumstances affecting the equitable nature of a
contract. ln a munidpalization case, he testified conceming the reasonable expectation period for
the supplier of power and transmission services to a municipality. ln two Surface Transportation
Board proceedings, he testified on the sufficiency of product market competition to inhibit the
exercise of market power by railroads transporting coal to power plants.
For one owner of the Trans-Alaskan Pipeline, he submitted testimony to FERC in 2010 conceming
cost pooling and related issues of cost and revenue allocation among co.owner.
For a landholder, Dr. Hieronyrnus examined the feasibility and value of an energy conversion project
that sought a longrterm lease. The analysis uras used in preparing contract negotiation strategies.
For an industrial dient considering development and marketing of a total energy system for
cogeneration of elec{ricity and lourgrade heat, Dr. Hieronymus developed an estimate of the
potential market for the system by geographic area.
For the U.S. Environmental Protection Agency (EPA), he was the principa! investigator in a series of
studies that forecasted future supply availability and production costs for various grades of steam
and metallurgical coal to be consumed in process heat and utility uses.
Dr. Hieronymus has been an invited speaker at numerous conferences on such issues as market power,
industry restructuring, utilig pricing in competitive markets, intemational developments in utili$ structure
and regulation, risk analysis for regulated investments, price squeezes, rate design, forecasting customer
response to innovative rates, intervener strategies in utility regulatory proceedings, utility deregulation,
and utility+elated opportunities for investment bankers.
Prior to rejoining CRA in June 2001, Dr. Hieronymus \Mas a Member of the Management Group at PA
Consulting, whict acquired Hagler Bailly, lnc. in October 2000. He was a Senior Mce President of Hagler
Bailly. ln 1998, Hagler Bailly acquired Dr. Hieronyrnus's former employer, Putnam, Hayes & Bartleft, lnc.
He raras a Managing Director at PHB. He joined PHB in 1978. From 1973 to 1978 he was a Senior
Research Associate and Program Manager for Energy Market Analysis at CFIA. Previously, he served as
a projed director at Systems Tedrnology Corporation and as an economist while serving as a Captain in
the U.S. Army.
Exhibit No. 6
Case No. GNR-E-11-03
W. Hieronymus,lPC
Page I of 8
CERTIFICATE OF SERVIGE
I HEREBY CERTIFY that on the 31$ day of January 2012 I served a true and
conect copy of the DIREGT TESTIMONY OF WILLIAM H. HIERONYMUS upon the
following named parties by the method indicated below:
Commission Staff
Donald L. Howell, ll
Kristine A. Sasser
Deputy Atto meys General
ldaho Public l.Jtilities Commission
472 West Washington (83702)
P.O. Box 83720
Boise, ldaho 8372O-OO7 4
Avista Corporation
MichaelG. Andrea
Avista Corporation
1411 East Mission Avenue, MSG23
P.O. Box 3727
Spokane, Washingto n 99220-37 27
PacifiCorp d/ila Rocky Mountaln Power
Daniel E. Solander
PacifiCorp d/b/a Rocky Mountain Power
201 South Main Street, Suite 2300
Salt Lake City, Utah 84111
Kenneth lGufmann
LOVINGER KAUFMANN, LLP
825 NE Multrcmah, Suite 925
Portland, Orcgon 97232
Exergy Development, Grand View Solar ll,
J.R. Simplot, Northwest and lntermountain
Power Producers Goalitlon, Board of
Commissioners of Adams County, ldaho,
and Clearwater Paper Gorporation
Peter J. Richardson
Grcgory M. Adams
RICHARDSON & O'LEARY, PLLC
515 North 27h Street (83702)
P.O. Box 7218
Boise, ldaho 83707
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kris. sasser@puc. idaho.oov
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CERTIFICATE OF SERVICE - 1
Exergy Development Group
James Carkulis, Managing Member
Exergy Development Grcup of ldaho, LLC
802 West Bannock Street, Suite 1200
Boise, ldaho 83702
Grand View Solar ll
Robert A. Paul
Grand View Solar ll
15690 Vista Circle
Desert Hot Springs, Califomi a 92241
J.R. Simplot Gompany
Don Sturtevant, Energy Director
J.R. Simplot Company
One CapitalCenter
999 Main Street
P.O. Box 27
Boise, ldaho 83707 -0027
Northwest and lntermountaln Power
Producers Coalition
Robert D. Kahn, Executive Director
Northwest and lntermountain Power
Producers Coalition
1117 MinorAvenue, Suite 300
Seattle, Washington 981 01
Board of Gommisslonerc of Adams
County, ldaho
Bill Brown, Chair
Board of Commissioners of
Adams County, ldaho
P.O. Box 48
Council, ldaho 83612
Glearwater Paper Corporation
Marv Lewallen
Gleanrvater Paper Corporation
601 West Riverside Avenue, Suite 1100
Spokane, Washington 99201
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bd brown@frontiemet. net
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CERTIFICATE OF SERVICE -2
Renewable Energy Coalltlon
Thomas H. Nelson, Attomey
P.O. Box 1211
Welches, Oregon 97067 -121 1
John R. Lowe, Consultant
Renewable Eneryy Coalition
12050 SW Tremont Street
Portland, Oregon 97225
Dynamis Energy, LLC
Ronald L. Williams
WILLIAMS BMDBURY, P.C.
1015 West Hays Street
Boise, ldaho 83702
Wade Thomas, General Counsel
Dynamis Eneryy, LLC
776 East Rivercide Drive, Suite 150
Eagle, ldaho 83616
ldaho Windfarms, LLG
Glenn lkemoto
Maqaret Rueger
ldaho Windfarms, LLC
672Blair Avenue
Piedmont, Califomia 9461 1
lnterconnect Solar Development LLG
R. Greg Femey
MIMURA LAW OFFICES, PLLC
2176 East Franklin Road, Suite 120
Meridian, ldaho 83642
Bill Piske, Manager
lnterconnect Solar Development, LLC
1303 East Carter
Boise, ldaho 83706
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Renewable Northwest Project
Dean J. Miller
McDEVlfi & MILLER LLP
420 West Bannock Street (83702)
P.O. Box 2564
Boise, ldaho 83701
Megan Walseth Decker
Senior Staff Counsel
Renewable Northwest Project
917 SW Oak Street, Suite 303
Portland, Oregon 97205
North Side Canal Company and Twin Falls
Ganal Company
Shelley M. Davis
BARKER ROSHOLT & SIMPSON, LLP
1010 West Jefferson Street, Suite 1O2 (837021
P.O. Box 2139
Boise, ldaho 83701 -21 39
Brian Olmstead, General Manager
Twin Falls Canal Company
P.O. Box 326
Twin Falls, ldaho 83303
Ted Diehl, General Manager
North Side Canal Company
921 North Lincoln Street
Jerome, ldaho 83338
Birch Power Company
Ted S. Sorenson, P.E.
Birch Power Company
5203 South 1 th East
ldaho Falls, ldaho 83404
Blue Ribbon Energy LLG
M. J. Humphries
Blue Ribbon Energy LLC
4515 South Ammon Road
Ammon, ldaho 83406
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CERTIFICATE OF SERVICE .4
X Email [e-mail]
Anon F. Jepson
Blue Ribbon Energy LLC
10660 South 540 East
Sandy, Utah 84070
ldaho Conservation League
Benjamin J. Otto
ldaho Conservation League
710 North Sixth Street (83702)
P.O. Box 844
Boise, ldaho 83701
Snake RiverAlliance
Ken Miller
Clean Energy Program Director
Snake RiverAlliance
350 North gh Street #8610
P.O. Box 1731
Boise, ldaho 83701
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CERTIFICATE OF SERVICE - 5