June 1, 2013 

Email I US Mail 

Portland General Electric Company 

121 SW Salmon Street • Portland, Oregon 97204 

PortlandGeneral.com 

Public Utility Commission of Oregon 

Filing Center 

550 Capitol Street, N.E., Ste. 215 

P.O. Box 2148 

Salem, OR 97301-2148 

RE: UM __ - PGE 2012 Renewable Portfolio Standard Compliance Report 

Enclosed please fmd an original and two copies of PGE's Renewable Portfolio Standard 

Compliance Report. The Report is submitted pursuant to OAR 860-083-0350 and provides 

information about how PGE has met its 2012 RPS target. 

As Attachment D to the Report, we have included per OPUC Staffs recommendation, a 

justification of hydro efficiency upgrade renewable energy credits (RECs) attributable to PGE's 

Faraday hydro facility. PGE strongly believes that upgrades to Faraday Units 1-5 are efficiency 

improvements eligible under ORS 469A.020 (3) to use for RPS compliance. Attachment E 

provides supporting documentation. 

Portions of this Report are Confidential and Subject totreat!fient as prescribed under 

OAR 860-001-0070 (Confidential Information) due to their commercially sensitive nature. Those 

confidential portions have been redacted. Hardcopies of the unredacted pages have been placed 

on ydlow paper in a separately sealed envelope bearing the legend "CONFIDENTIAL." Please 

do not place the confidential portions on the OPUC website, nor release it to anyone outside the 

Public Utility Commission Staff. 

Please store the hardcopy in a locked file cabinet. If you are unable to honor these requests, 

please notify us immediately. 

If you have any questions or require further information, please call David Weitzel at (503) 464-

7352 or Richard George at (503) 464-7611. Please direct all formal correspondence and requests 

to the following email addresses: richard.george@pgn.com and pge.opuc.filings(ci),pgn.com 

Sincerely, 

h-~ 

Jay Tinker 

Director, Regulatory Policy and Mfairs 

Enclosures 
Portland General Electric 

Renewable Portfolio Standard 

Oregon Compliance Report 

2012 

As an introduction and summary of the Compliance Report, answer the following 

questions: 

Why is PGE submitting a Compliance Report? What information was used as the 

basis of this Compliance Report? 

PGE is submitting this Compliance Report to fulfill the requirements of 

ORS 469A.170. The report is based on information from PGE's 2009 

Integrated Resource Plan (IRP), PGE's 2011 IRP Update, PGE's 2012 IRP 

Update and PGE's most recent RPS Implementation Plan. 

Did the company meet its Renewable Portfolio Standard (RPS) target, and if not, 

describe in detail why not? 

Yes, PGE has met its 2012 Renewable Portfolio Standard (RPS) target. 

The compliance details are provided in this report. 

Provide the following information in response to the requirements of OAR 860-083-0350: 

OAR 860-083-0350(2)(a) 

The total number of megawatt-hours sold to retail electricity consumers covered 

by ORS 469A.052 by the electric company or sold in the service areas of each electric 

company covered by ORS 469A.052 by the electricity service supplier. 

Response: 

For 2012, the total number of megawatt-hours sold to retail electricity consumers was: 

PGE's Total Billed Load: 17,97 5,810 megawatt-hours. 

Source: 2012 PGE PERC Form 1 (Page 304, Row 41, Column (b)). 

OAR 860-083-0350(2)(b) 

The total number of renewable energy certificates, identified as either 

unbundled or bundled certificates, acquired in the compliance year and used to meet 

the renewable portfolio standard. 

Response: 

1 
There are no unbundled or bundled certificates acquired in compliance year 2012 that 

will be used to meet the renewable portfolio standard requirement for compliance year 

2012. 

OAR 860-083-0350(2)(c) 

The total number of renewable energy certificates, identified as either unbundled 

or bundled certificates, acquired on or before March 31 of the year following the 

compliance year and used to meet the renewable portfolio standard. 

Response: 

There are no bundled certificates acquired in 2013 that will be used to meet the 

renewable portfolio standard requirement for compliance year 2012. 

There are 140,800 unbundled certificates acquired in 2013 that will be used to meet the 

renewable portfolio standard requirement for compliance year 2012. 

OAR 860-083-0350(2)( d) 

The total number and cost of unbundled renewable energy certificates, identified 

as either banked or non~banked certificates, used to meet the renewable portfolio 

standard. 

Response: 

The table below shows the total number and cost by facility of the unbundled renewable 

energy certificates used to meet the renewable portfolio standard. All unbundled RECs 

used were banked. 

OAR 860-083-0350(2)(e) 

The total number of banked bundled renewable energy certificates that were 

used to meet the renewable portfolio standard. 

Response: 

The total number of banked bundled renewable energy certificates that will be used to 

meet the renewable portfolio standard for compliance year 2012 is: 

719,033 (898,791 1 - 179,758) 

1 See response to 2(1). 

2 
OAR 860-083-0350(2)(1) 

The total number of renewable energy certificates, identified as either bundled or 

unbundled certificates, issued in the compliance year that were banked to serve Oregon 

electricity consumers. 

Response: 

There are no unbundled certificates that were issued in the compliance year that were 

banked to serve Oregon electricity consun1ers. 

As ofthis filing, there are 2,564,331 bundled certificates that were issued for the 

compliance year 2012 that will be banked to serve Oregon electricity consumers. 

See the 2012 column in Attachment C for detail by facility. 

OAR 860-083-0350(2)(g) 

For electric companies, unless otherwise provided under subsection (2)(k) of this 

rule, the total number of renewable energy certificates included in the rates of Oregon 

retail electricity consumers that were sold since the last compliance report, including: 

(A) The names of the associated generating facilities; and 

(B) For each facility, the year or years the renewable energy certificates were issued. 

Response: 

There are no renewable energy certificates included in the rates of Oregon retail 

electricity consumers that were sold since the last compliance report. 

OAR 860-083-0350(2)(h) 

Unless otherwise provided under subsection (2)(k) of this rule, for each 

generating facility associated with the renewable energy certificates included in 

subsections (2)(b), (c), (f), or (g) of this rule the following information: 

(A) The name of the facility; 

(B) The county and state where the facility is located; 

(C) The type of renewable resource; 

(D) The total nameplate megawatt capacity of the facility; 

(E) For an electric company, the Oregon share of the nameplate megawatt capacity 

of the facility; 

(F) The year of the first delivery of qualifying electricity or the first year of the 

contract for the purchase of unbundled renewable energy certificates; and 

(G) The duration ofthe contract or the amortization period of a facility owned by 

the electric company or the planned lifetime of a facility owned by the electricity service 

supplier. 

Response: 

3 
See Attachment A. 

OAR 860-083-0350(2)(i) 

The amount of alternative compliance payments the electric company or 

electricity service supplier elected to use or was required to use to comply with the 

applicable renewable portfolio standard. 

Response: 

There are no alternative compliance payments that PGE elected to use or was required to 

use to comply with the applicable renewable portfolio standard. 

OAR 860-083-0350(2)(j) 

For an electric company, sufficient data, documentation, and other information 

to demonstrate that any voluntary alternative compliance payments were a reasonable 

compliance method. 

Response: 

PGE will not be making any voluntary alternative compliance payments. 

OAR 860-083-0350(2)(k) 

Documentation of use of renewable energy certificates from the system under 

OAR 330-160-0020 established for compliance with the applicable renewable portfolio 

standard. 

Response: 

The attached WREGIS report (Attachment B) shows all renewable energy certificates to 

be used to meet the 2012 renewable portfolio standard. The RECs are currently in an 

active sub-account named "2012 OR RPS." Within 30 days of the approval of POE's 

RPS Compliance Report by the Commission, the RECs will be retired to a retirement 

sub-account named "OR RPS 2012." To validate compliance, PGE will then send a 

retirement report from WREGIS to the Commission. 

OAR 860-083-0350(2)(1) 

For each electric company, a detailed explanation of any material deviations 

from the applicable implementation plan filed under OAR 860-083-0400, as 

acknowledged by the Commission. 

Response: 

The table below presents a comparison between our 2009 Implementation Plan forecast 

for our 2012 REC requirements, and our 2012 Compliance Report filing. The largest 

change is the lower REC requirement, a drop of 172,857 MWhs. This decrease is due to 

lower load requirements resulting from the continued impact of economic recession. It 

should also be noted our 2011 Compliance plan listed a similar drop of 135,883 for the 

year 2011 versus what had been predicted in 2009. 

4 
Another material difference is the number of unbundled RECs used for compliance. As 

we stated in our 2011 Implementation Plan: 

PGE intends to continue monitoring REC markets and may purchase or sell 

bundled or unbundled RECs in the market when price is perceived to be a good 

value in relation to other means of achieving RPS compliance. 

There were unbundled RECs available that were seen to be a good value; so these RECs 

were purchased and are retired here. These retirements enable us to preserve some of our 

bundled RECs for use in later compliance years. 

One other difference- also noted in the 2011 Compliance Plan, is the inclusion of the 

River Mill and Sullivan hydro upgrades. The number ofRECs are not material in total 

REC numbers, but are called out for completeness. PGE had been including hydro 

upgrades of vintage 1999 or later in its IRP and Implementation Plan filings. Following 

those filing we determined that the appropriate year for including such upgrades was 

1995 (see ORS 469A.020- Qualifying electricity; age of generating facility); resulting in 

the inclusion of the two additional facilities. Again - the total number of RECs here is 

small; 3,240 (about 113 MWa). 

One other note for the Sullivan project- some of the RECs generated there are counted 

as facility upgrades, while some are counted as low-impact hydropower RECs. The table 

below includes the project broken out in the two separate categories. PGE is limited to 

50 MWa oflow-impact hydropower, with portions of the total coming from Sullivan, 

Pelton, and Round Butte. 

The other differences are mainly related to the increased use of unbundled RECs, and 

lower projected need. This introduces timing issues in REC retirement. Our initial 

forecast relied on RECs that would be generated in 2009, however due to the factors 

discussed above, 2012 compliance only relies on RECs generated in 2008 or earlier. 

Thus we do not use any RECs from Biglow 2, and lower amounts from hydro upgrades 

as well as Sunway than initially projected. 

Projection in Actual Deviation 

Resource 2009 RECs in from Implementation Compliance Forecast Plan Plan 

Unbundled REGs - 179,758 179,758 

Biglow 1 · 317,584 137,134 (180,450) 

Biglow2 29,702 (29,702) 

North Fork Upgrade 6,705 1,776 (4,929) 

Faraday Upgrade 7,347 2,934 (4,413) 

Round Butte Upgrade 49,219 27,373 (21,846) 

Willamette Falls Hydro Upgrade- Sullivan 2,299 2,299 

River Mill 941 941 

Pelton-Round Butte Low-Impact Hydro 439,200 432,864 (6,336) 

5 
Willamette Falls Low-Impact Hydro- Sullivan 6,336 6,336 

PPM Klondike II 159,009 75,011 (83,998) 

Vansvcle Ridge 62,514 32,365 (30,149) 

Sunway 1 26 (26) 

Sunway 2 341 (341) 

Total 1,071,648 898,791 (172,857) 

OAR 860-083-0350(2)(m) 

As specified in OAR 860-083-0100, the total number and cost of bundled 

renewable energy certificates used for compliance. 

Response: 

OAR 860-083-0350(2)(n) 

For each electric company, its projected annual revenue requirement as 

calculated in OAR 860-083-0200 and its total cost of compliance. 

Response: 

PGE's projected annual revenue requirement for 2012 is: 

$1,709,111,606. 

Source: Table 1- Base Rates 

Estimated Effect on Customer Total Electric Bills 

2012 COS Only 

PGE's total cost of compliance for 2012 is: 

[2(d) + 2(m)] = $3,859,811 

Cost of compliance as percentage of revenue requirement is: 

0.23% 

OAR 860-083-0350(2)( o) 

For each electricity service supplier, its total cost of compliance, its average cost 

of compliance, and its cost limit as specified in OAR 860-083-0300(2), including all 

calculations. 

Response: 

Not applicable. 

OAR 860-083-0350(2)(p) 

6 
For each electric company, an accounting of the use of the renewable energy 

certificates and alternative cost payments consistent with OAR 860-083-0300(3) if the 

cost limit in ORS 469A.l 00(1) is reached for the compliance year. 

Response: 

The cost limit in ORS 469 A.lOO(l) was not reached for the 2012 compliance year. 

OAR 860-083-0350(2)(q) 

For each electricity service supplier, an accounting of the use of the renewable 

energy certificates and alternative cost payments consistent with OAR 860-083-0300(3) 

if the cost limit in OAR 860-083-0300(2) is reached for the compliance year. 

Response: 

Not applicable. 

OAR 860-083-0350(2)(r) 

As specified in OAR 860-083-0100, the number and total cost of all bundled renewable 

energy certificates issued. 

Response: 

See Attachment C. 

OAR 860-083-0350(2)(s) 

As specified in OAR 860-083-0100, the number and total cost ofbundled renewable 

energy certificates issued that are associated with new qualifying electricity since the last 

compliance report. 

Response: 

See Footnote 9 on Attachment C. 

OAR 860-083-0350(6)_ 

Each electric company subject to ORS 469A.052 and each electricity service supplier 

subject to ORS 469A.065 must post on its web site the public portion of the four most 

recent annual compliance reports required under this rule and provide a copy of the most 

recent such report to any person upon request. The public portions of the most recent 

compliance report must be posted within 30 days of the Commission decision in section 

(5) of this rule. The posting must include any Commission determinations under section 

(5) of this rule. 

Response: 

PGE will comply with this requirement within 30 days of the Commission decision. 

7 
OAR 860-083-0350(7) 

Consistent with Commission orders for disclosure under OAR 860-038-0300, each 

electric company subject to ORS 469A.052 and each electricity service supplier subject 

to ORS 469A.065 must provide information about its compliance report to its customers 

by bill insert or other Commission-approved method. The information must be provided 

within 90 days of the Commission decision in section (5) of this rule or coordinated with 

the next available insert required under OAR 860-038-0300. The information must 

include the URL address for the compliance reports posted under section (6) of this rule. 

Response: 

PGE will comply with this requirement within 90 days of the Commission decision. 

8 
PGE 2012 RPS 

Attachment A 
Attachment A 

lWilmpactliydrosubjett to50t..maCaP. 

*Assoclatedwithhydroefficlencyupgrades. 

"*QF=QualifyingFacility 

NM=NetMetering 

PPA = PWier Purchase Agreement 

SVP"' Solar Volumetric Project 

UO=U~IityOwned 

UM _. PGE lOll RPS Complianc.. Report 

Attachment A 

Pagel 
PGE 2012 RPS 

Attachment B 
~-WECC 

Certificates in Subaccount 

Select 

All 

Transfer 

Quantity 

Page 1 of 11 

SubAccount WREGIS 

GUID 

' II 

Generator 

Plant-Unit 

Name 

Fuel Type 

Hydroelectric 

Water 

Vintage 

Year/Month 

Certificate 

Serial 

Numbers 

Quantity AZ BC CA co MT NV NM TX 

UM __ - PGE 2012 RPS Compliance Report 

Attachment B 

Page 1 

WA OR AB UT 

Greene Energy 

Eligible 

Printed Date: 5/23/2013 4:38:33 PM 

Ecologo 

Certified 

No 

Hydro 

Certification 

No 

SMUD 

Eligible 

NERC 

E-Tag 

Matched 

No 

No No 

No No 

No No 

No 
Certificates in Subaccount (Continue) 

Page 2 of II 

Brown Lake 

Generating 

StationBrown Lake 

Generating 

Station 

Hydroelectric 

Water 

Hydroelectric 

Water 

UM __ - PGE 2012 RPS Compliance Report 

Attachment B 

Page2 

Printed Date: 5/23/2013 4:38:33 PM 

No 

No 

No 

No No No 

No No No 
Certificates in Subaccount (Continue) 

W876 

W1492 

Page 3 ofll 

PeltonPelton Gen 3 

Miller CreekMiller Creek 

Generating 

Facility Unit 

1 

Brown Lake 

Generating 

StationBrown Lake 

Generating 

Station 

Hydroelectric 

Water 

UM __ - PGE 2012 RPS Compliance Report 

Attachment B 

Page3 

Printed Date: 5/23/2013 4:38:33 PM 

No 

No No 

No No 
Certificates in Subaccount (Continue) 

Page 4 ofll 

2012 OR 

RPS 

Round Butte 

W879 -Round 

W1909 

Butte 3 

Brown Lake 

Generating 

StationBrown Lake 

Generating 

Station 

UM __ - PGE 2012 RPS Compliance Report 

Attachment B 

Page4 

Printed Date: 5/23/2013 4:38:33 PM 

No No 

No No No 

No 

No 

No 
Certificates in Subaccount (Continue) 

Page 5 ofll 

2012 OR 

RPS 

Miller Creek -

Miller Creek 

Unit 2 

Miller Creek -

Miller Creek 

Generating 

Facility Unit 

1 

Miller CreekMiller Creek 

Generating 

Facility Unit 

1 

Round Butte 

-Round 

Butte 3 

PeltonPelton Gen 2 

Hydroelectric 

Water 

Hydroelectric 

Water 

Hydroelectric 

Water 

Hydroelectric 

Water 

Hydroelectric 

Water 

UM __ - PGE 2012 RPS Compliance Report 

Attachment B 

PageS 

Printed Date: 5/23/2013 4:38:33 PM 

No No 

No No 

No 

No No 

No 

No 
Certificates in Subaccount (Continue) 

Page 6 ofll 

2012 OR 

RPS 

2012 OR 

RPS 

2012 OR 

RPS 

Hydroelectric 

Water 

UM __ - PGE 2012 RPS Compliance Report 

Attachment B 

Page 6 

Printed Date: 5/23/2013 4:38:33 PM 

No No 

No No 

No 

No 

No 

No No 

No No 
Certificates in Subaccount (Continue) 

Page 7 ofll 

2012 OR 

RPS W839 

River MillRiver Milll 

Hydroelectric 

Water 

Alternate 

Use 

UM __ - PGE 2012 RPS Compliance Report 

Attachment B 

Page7 

Printed Date: 5/23/2013 4:38:33 PM 

No 

No 

No No No 

No 

No No 

No 
Certificates in Subaccount (Continue) 

Page 8 ofll 

UM __ - PGE 2012 RPS Compliance Report 

Attachment B 

PageS 

Printed Date: 5/23/2013 4:38:33 PM 

No No 

No 

No 

No No 

No 

No 
Certificates in Subaccount (Continue) 

Page 9 ofll 

River MillRiver Milll 

Miller CreekMiller Creek 

Unit 2 

Alternate 

Use 

Alternate 

Use 

Hydroelectric 

Water 

UM __ - PGE 2012 RPS Compliance Report 

Attachment B 

Page9 

Printed Date: 5/23/2013 4:38:33 PM 

No 

No No 

No No 

No No 

No No 

No No 

No No 
Certificates in Subaccount (Continue) 

Page 10 of 11 

UM __ - PGE 2012 RPS Compliance Report 

Attachment B 

Page 10 

Printed Date: 5/23/2013 4:38:33 PM 

No No 

No No 

No 

No No 

No No 

No 

No 

No No No 
Certificates in Subaccount (Continue) 

Page 11 of 11 

UM __ - PGE 2012 RPS Compliance Report 

Attachment B 

Page 11 

Printed Date: 5/23/2013 4:38:33 PM 

No 

No 

No 

No 
PGE 2012 RPS 

Attachment C 
OAR 860-083-0350(2)(r) & (2)(s) 

B'gi"""C<ln)O;mWindFarm-BigioNPhase1 

B'gioNcan)'OI1WindFarm-BgloNPhase2 

Bgt"""can)-OnWindFarm-BgkmC<ln;oo3 

Vans}':le W111d P~ect- VanS}':Ie Wild Plqect 

Kbndikeii-KioodikeWindPO'M!fiiLLC 

Peltoo-PeltooGen1 

Peltt11-Peltt11Gen2 

Pelton-PeltooGen3 

RoundButte-RoundButte1 

Round8utte-Round8utte2 

~~:!~;;~=~~~!::; ~~ect-SuiWrul WiHametle Falls H}droe!ectric Prqect- SUTINa!l geo 9 

Round8utte-Round8utte2[2] 

~~=:~;a·l:~;:=~rqect-Sultivan PJ 

NorthFork-NorthFork2[4J 

Faraday-Faraday1[41!5] 

Faraday-Faraday6{4J 

RwerMii-R~MIII1{4][6] 

OOOT-15 & 1205 -OOOT-15 & 1205 

ProLogisEast1-Prd.og1SEast1 

ProloglsEast1-ProLogisEast1 LUI 

ProloglsEast2-ProLogisEast2 

ProLoglsEast2-ProLogisEast2[111 

PrologisPDXPark4-ProLogisPDXParl\4 

ProLoglsPOXPark4-ProLogisPDXParl\4{8} 

JeornferD.strictCenter#1-Prd.ogls-Jennrfilr1 

JenlllferCistrictCenterii'1-Prologls-Jennrfilr1[llJ 

JenniferD.strictCentarii'2-Prologis-Jenn!filr2 

JenrnferCistrictGenterll'2 -Prologis-Jenn~er2 {8} 

Jenn~erCistrictCenter#3-Prd.ogls-JenMer3 

JennlferCisllictCenterlt3-Prd.ogls-Jennifer3[8] 

PDXPrd.ogisPark1-ProLogs-Park1 

PDXPrd.oglsPark1-ProLogs-Park1 [8] 

PDXProLoglsPark2-ProLogs-Park2 

PDXPrd.ogiSPark2-ProLogs-Park2{8} 

SouthshoreCorpBidgA-Prologls-SouthshoreA 

SouthslloreCorpBidgA-ProLogls-SouthshoreA[8] 

SouthshoreCorpB!dgC-ProLogis-Southsh<JreC 

SouthslloreCorpB!dgC-ProLogis-SouthshoreC[8] 

PGE-SPO-G1-PGE-SPO..G1 

PGE-SPO-G2- PGE-SPO..G2 

PGE-SPO-G3- PGE-SPO-G3 

PGE-SPO-G4- PGE-SPO-G4 

PGE-SPO-G5- PGE-SPO-G5 

PGE-SPO-G6- PGE-SPO-G6 

PGE-SPO-G7- PGE-SPO-G7 

PGE-SPO-GB- PGE-SPO-G8 

PGE-SPO-G9 • PGE-SPO-G9-3CSdar, LLC 

PGE.SPO-G10- PGE-SPO-G10 

PGE-SPO-G11-PGE-SPO-G11 

PGE-SPO-G12- PGE-SPO-G12 

PGE-SPO-G13- PGE-SPO-G13 

PGE-SPO-G14- PGE.SPO-G14 

H;droeiEctncWater 

H)l'lroelectncWat.er 

H;rlroelectncWater 

H}rlroe!ectncWaler 

H;droelectncWater 

H;rlroelecbicWater 

H;rlroelectncWater 

H;rlroelecllicWi!l.er 

AltemateUse[11 

AitemateUse[1] 

AltemateUse[1] 

AltemateUse[1] 

AltamateUse[1] 

AltemateUse[11 

AltamateUse[11 

Sd~ 

Sd~ 

SdM 

SdM 

Sd~ 

Sd~ 

SdM 

Sd~ 

PGE.SPo.G15-PGE.SPO-G15 Sdar 

PGE.SPO-G16 • PGE.SPO-G16 191 Sdar 

PGE.SPO-G17.01!Ckarnas- PGE-SPO-G17-Fred Me)-er Stores, Inc 191 SOlar 

PGE-SPO-G1S-PGE-SPO-G1S [9] 

PGE-SPO-G19-Kohlst'Epartmentstcre-Ganyoo Rd l>eilwrton[9[ Solar 

PGE-SPO-G20- PGE-SPO-G20 [llJ SOlar 

PGE.SPO-G21-PGE-SPO-G21 [llJ 

PGE-SPO-G22- PGE-SPO-G22 [9J 

PGE-SPO-G23- PGE-SPO-G23 [9J 

PGE-SPO-G24- PGE-SPO-G24 [9J 

PGE-SPO-G25- MtAngel School Dstict [9] Sdar 

PGE-SPO-G26 • PGE-SPO-G26 [llJ Sdar 

PGE-SPO-G27 • PGE-SPO-G27 [9J 

PGE-SPO-G28- PGE-SPO-G2S [9J Solar 

PGE-SPO-G29- PGE-SPO-G29[9] SOlar 

PGE-SPO-G30- PGE-SPO-G30 [9] 

PGE-SPO-G31 - PGE-SPO-G31 {9] 

PGE-SPO-G32- PGE-SPO-G32 {9] Solar 

PGE-SPO-G33- PGE-SPO-G33 [9J SOlar 

PGE-SPO-G34- PGE-SPO-G34 [9] 

Baldod<SolarHigtw.ay-Ba!doc:l<:Sotar[llJ 

Baldod<SolarHigtw.ay-Ba!doc:l<:Solar[8] 

B!;!levue So~. LlC- Bel!<M~eSolar, LLC [9] 

B!;!levueSoar, LlC-Bel!eweSolar, LLC[BJ Sdar 

Patland Habd~allonGanter-POitland Hablrtation Center[91 SOlar 

PatlaridHablllatiOilCe!lter-PortlandHabJrtatfonCenter[BJ 

OutbackSotar-OutbackSotar[9] 

Outback Solar- Outbad!: Solar (8] Sdar 

Yamhil Solar, LLC- Yamh1USolar. LLC [9[ SOlar 

Yamhil SOlar, LLC- Yamhill Solar, LLC (8] 

GramiTotll 

70,4BS 

207,413 

96,610 

101,704 ""' 

36,992 

299,042 

286,305 

10,334 

39,D26 

41,946 

4,257 

3,257 '·"" 

'"'' 

382,535 

210,671 

132,807 

142,16-EI 

137,617 

65,510 

411,903 

122,072 

40,010 

41,163 

7,166 

4,295 

343,900 

159,480 

68,885 

186,211 

147,166 

131,758 

105,142 

394,424 

437,378 

127,259 

3,748 

16,423 

4,753 

4,lllll 

3,142 

3,480 

"~ 

" "' 

312,099 

74,902 

173,511 

160,290 

130,158 

129,897 

449,314 

126,862 

6,634 

4,087 

3,072 

3,938 

1,678 

"' "' 

~ 

" 

~ 

~ 

" ' 

355,370 

438,002 

384,679 

194,847 

140,290 

140,290 

119,002 

503,493 

116,806 

8,112 

'"' "' 

"' "' 

'"' "' 

'" m 

m "' 

337,470 1,759,468 

410,406 1,383,140 

360,639 818,571 

443,382 

211,993 1,188,755 

185,752 917,472 

133,741 713,706 

133,741 775,007 

96,812 507,862 

483,846 2,553,168 

2,059,933 

111,375 614,708 

7,734 26,228 

~ 

m 

~· ~' 

"' "' 

= 

"' 

95,469 

103,079 

19,487 

16,827 

12,064 

14,121 

7,495 

'" '" 

'" "' 

5" 

"' 

'" '" 

"' 538 

54' 

"' 

.... "' 

375 

"' 

247 

"' '" "' 329 329 

258 258 

139 139 

120 120 

w 

911 98 

1,880 1,880 

1,880 1,880 

1,754 

887 1,754 

"" 1.251 '"' 1.251 1.251 

2,188,166 2,293.262 2,574,289 3,174,054 2,564,331 14.123,745 

18,781,750 

12:,853,3Zo4 

8.290,987 

Note: The tab~ above represents all actual buridled REGs iss.ued and created in PGE's WREGIS acoount for 2007-2012 as ctS-14-13 anrl does net tala! into account REGs that h<m! been ret red or sold. Noestimat100s have 

been made. Pteaseseefootndesbelow. 

[1JAHemateUse,HydroEfiJ::)E!ncyUpgrades 

[2J Hydro Effie)E!ncy Upgrades for Round Butte 2 & 3 are not included fran June 2009 to December2012. These RECs hawmt ~been cmated due to issues w.th WREGIS's abolily to cmate these REGs.. PGE is working 

W!lhOOOEtoresolvethese1ss.ues. 

PJ H;rlro Efficjency Upgrades for Sulivan are not induded lium May 2009 to December 2012 These REGs have not yet been created due to 1ssues concemmg the metho::kiogy tc.the ca!culaboo ofhydroe'fidencyupgrades. 

PGE is currently in the process clupbad111g these RECs rnto WREGIS. 

[4] Hydro Effie~encyUpgrades for North FolK 2, Faraday 1-S, and R~r M1ll-J ate not included from Januil!Y2010 to December 2012. These REGs haYe not)':'!: been created due to ssues coocernlog 1he methoddegyfo:the 

ca!culation c1 hydro e'I'Ciencyupgrades. PGE s currently 111 the PfCWSScfUploading these REGs 1ntoWREGIS 

[5]Faraday1nctudesFaradayun~s1-5. Theseunrtsareaggregatedin'NREGIS. 

[6]RiverMIII11nclldesRiwrMIIunls1-3 Theseunrtsareaggregatedin'NREGIS 

[7] No REGs haw been amted for Rourid Butte 3 fot2012 due to ooncems around multi-fuel spirts. These RECs'M! beup!oaded 11'1 2013. There should be approximately468,823 REGs spl,t be!Yoeen h)rlmand alemate use. 

[8] SdarGapaclty Standard 2.1 REGs 

[9JNIM'QUallf)1ngEiectncty 

li~I-·PGERPSComp:::cc;:~ 

Pagol 

tro;:~ta! """""'" '~ '-=~~I;::;~;:I~~;:r;~~;r;:~g 2001 I 2008 I 2009 I 2010 ! 2011 I 13200$ 370,947$5,052,522$4,542,350$4,122,204$4,693,727 

13000 2,074,516 4,881,278 5,697,530 

1,326,354 
PGE 2012 RPS 

Attachment D 
UM __ - PGE 2012 RPS Compliance Report 

Attachment D 

Page 1 

As part of this compliance filing, PGE includes 1,236 of renewable energy credits ("RECs") from Faraday 

units 1-5. We believe these RECs qualify for inclusion in this filing because they represent eligible 

generation from an allowable resource- a hydroelectric efficiency improvement made after January 1, 

1995.1 PGE included 2,609 RECs from the Faraday units in our 2011 compliance filing that was approved 

by the commission in Order 12-456 (UM 1605). 

In the process of registering Faraday units 1-5 in the Western Renewable Energy Generation 

Information System ("WREGIS"), based on consultation from the US Army Corps of Engineers 2 ("Corps"), 

the Oregon Department of Energy ("department") has raised a concern that the physical improvements 

made to the Faraday units may not be not eligible for generating qualifying electricity under the statute3 

and departmental rules. 4 Notwithstanding the Corps' opinion, PGE strongly disagrees and asks the 

commission to specifically approve RECs from the incremental improvements made to Faraday units 1-

5 as qualifying electricity for this and future compliance filings. In forming our opinion, we review the 

upgrades themselves, the legislative history behind the development ofthe Renewable Energy Standard 

("RES"), the adoption of department rules, and the Corps letter. We take each in turn below. 

Modifications of Faraday Units 1- 5 produced a minimum 5% increase from generator improvements 

without additional impoundment, additional diversion or additional flow 

In early 1996, flooding in the Clackamas River drainage caused damage to the generating units at 

Faraday. PGE performed the following improvements on the turbines at Faraday: rewind of the 

generator rotors and stators for Units 1, 2, 3, and 5 and installation of a new generator for Unit 4. The 

copper cross-section ofthe new stators was increased, allowing improved temperature performance, 

and resulted in an increased rating for the generators. Because the units had previously been generator 

limited, these changes allowed increased output. Following those improvements, the facility showed a 

conservative 5% improvement in unit performance. The manufacturer's estimate of performance also 

suggested that PGE would see a 6-9% improvement in performance. However, and importantly for the 

future adopted RES, the Faraday lake impoundment remained at the same level, PGE did not change the 

1 ORS 469A.020 (3) provides that "Electricity from a hydroelectric facility that became operational before January 

1, 1995, may be used to comply with a renewable portfolio standard if the electricity is attributable to efficiency 

upgrades made on or after January 1, 1995." ORS 469A.025 (4)(b) also provides a similar provision. 2 Email to Julie Peacock, ODOE, from Brian Shenk, USACOE. 3 ORS 469A.020 (3), 469A.025 (4)(b) 4 OAR 330-160-0050 
UM __ - PGE 2012 RPS Compliance Report 

Attachment D 

Page2 

capacity of the diversion structure and PGE did not appropriate additional water from the Clackamas 

River. 

Statutory Language and Legislative History Support Efficiency Upgrades at Faraday as Generating 

Qualifying Electricity 

In 2007, the Oregon Legislature adopted the RES. The language in this bill came directly from the 

Renewable Energy Working Group ("REWG"), the work product of which was significantly influenced by 

a smaller group of activists, utilities and customer representatives which called itself the "RPS Discussion 

group." The REWG grew from Governor Kulongoski's 2005 Renewable Energy Action Plan ("REAP"). The 

REAP specifically called for the creation of the REWG and stated that the goals of pursuing renewable 

energy were: risk mitigation, economic development and environmental benefits. 5 In addition, the REAP 

charged the REWG to "identify and support generation efficiency improvements, such as those 

performed by the utilities ... [and] support maximum generation efficiency for new projects in Oregon, 

while safeguarding the environment." 6 

It was in this context that the provision for allowing efficiency improvements at hydroelectric facilities to 

generate qualifying electricity was drafted. Efficiency improvements contribute to all three goals. 

Similarly, the improvements at Faraday contributed to all three goals: increasing renewable generation 

(risk mitigation), investing in infrastructure and generating more energy from the same water. This is 

consistent with the REAP charge to the REWG of achieving generation efficiency improvements while 

safeguarding the environment. 

The broader question is, however, what is meant by "efficiency upgrade?" Throughout the REWG 

process, the language took different forms. In an August 11, 2006, letter from several representatives of 

consumer owned utilities to then Director Mike Grainey, the language was "hydro efficiency 

upgrades."7 A letter in September from the same representatives, described the eligible power as 

5 Oregon Renewable Energy Action Plan of 2005, pp. 3 to 5. 6 Oregon Renewable Energy Action Plan, at 26. 7 See, Letter of August 11, 2006, to Mike Grainey from Tom O'Connor, OMEU, Don Goddard, OPUDA and Dick 

Wanderscheid, City of Ashland. 
UM __ - PGE 2012 RPS Compliance Report 

Attachment D 

Page3 

"incremental electricity produced as a result of improvements to existing hydroelectric generation." 8 A 

letter from the RPS Discussion Group to the chair of the REWG, Mike McArthur and Bill Drumheller, 

noted whether utilities would be able to count "incremental improvements at existing hydroelectric 

facilities." 9 In a tracking document developed by the REWG, the term was "increment of improvement 

resulting from efficiency upgrades." Once the term "efficiency upgrades" was settled on, it remained as 

a consistent reference in succeeding tracking documents. 10 Possibly influential on the choice of wording 

was Washington's 1-937, adopted contemporaneously in November 2006, allowing RECs from "efficiency 

improvements" 11 and opinions of national environmental organizations. 12 

Utilizing standard statutory interpretive guides, 13 PGE believes efficiency has its plain meaning- "the 

ratio ofthe useful energy delivered by a dynamic system to the energy supplied to it." 14 1nformed by 

legislative history, including that of the REWG and REAP, we believe the legislature intended to 

encourage improvement- the ratio- in the energy delivered from hydroelectric facilities based on the 

same energy supplied- the water- through investment in existing infrastructure. It likely did not mean 

to create a technical efficiency versus capacity issue but rather meant to refer to general incremental 

improvements. 15 To the extent that it did consider efficiency versus capacity, it did so in relation to 

protecting the environment. We believe the improvements at Faraday are exactly what the legislature, 

REWG and REAP wanted: they were made to existing infrastructure, they increase the energy produced 

at the facility from the same input of water, and they safeguard the environment by not increasing the 

diversion or impoundment. 

8 See, Letter of September 6, 2006, to Mike Grainey and Bill Drumheller from Tom O'Connor, OMEU, "fleshing out" 

the earlier letter. 9 Letter of September 7, 2006, to Mike McArthur and Bill Drumheller, from RPS Discussion Group 10 See Oregon Draft RPS and Related Policy Legislative Package Outline, 9/12/2006; 10/5/2006; and 11/6/2006 11 RCW 19.285.030 (11) states: "Eligible renewable resource" means ... Incremental electricity produced as a 

result of efficiency improvements ... where the additional generation ... does not result in new water diversions 

or impoundments. 12 See http://www.hydroreform.org/policy/rps "The Coalition believes that the following principles should be 

applied for hydropower under any RPS: l.No new dams; 2.No existing hydropower except incremental hydropower 

that includes: Capacity additions at existing projects, Efficiency improvements at existing hydro projects; and 3. 

Hydropower projects that take additional steps to protect the local system- for example, through the Low Impact 

Hydropower Institute's certification program." 13 See e.g., ORS 174.010, ORS 174.020, the text and context of the provision, and PGE v. Bureau of Labor and 

Industries, 317 Or 606, 610-12, 859 P2d 1143 (1993), as modified by State v. Gaines, 346 Or 160, 206 P3d 1042 

(2009). 

14 http://www.merriam-webster.com/dictionary/efficiency, 2b. 15 Compare ORS 469A.020 (2) allowing energy from other than hydro facilities to comply if "attributable to capacity 

or efficiency upgrades." 
UM __ - PGE 2012 RPS Compliance Report 

Attachment D 

Page4 

Under the Department's Administrative Rule, the Efficiency Upgrade at Faraday Generates Qualifying 

Electricity and Is Not Barred Due to Prohibition On Capacity Upgrades 

In early 2011, the department adopted rules implementing the 2007 law. These rules established how 

the department would interpret the statutory language. The rules state that: 

Efficiency upgrades from an Oregon RPS qualifying hydroelectric facility, refers to additional 

incremental qualifying electricity production at an existing hydroelectric facility due to upgrades 

to existing generators, turbines and other Department-approved equipment changes. Efficiency 

upgrades do not include increased generation achieved through increased impoundments or 

increased appropriation or diversions of water. 16 

PGE's improvements at Faraday fall within the bounds of this rule. The improvements were made to 

existing generators and did not involve increased impoundments, increased appropriation or increased 

diversions of water. 

This is not the end of the inquiry however, as the rule also forbids capacity increases from generating 

qualifying electricity. In this regard, the rule states that: 

Capacity upgrades to a hydroelectric project are not eligible under ORS 469A.025(4)(b) for the 

Oregon RPS. Capacity upgrades to a hydroelectric project include any increase in generating 

capacity other than an increase from an efficiency upgrade. 17 

However, we do not believe the improvements to Faraday constitute capacity upgrades. To inform this 

opinion, we look to the "legislative history" behind the rule adoption. During the rule advisory 

committee process in 2010, the debate as to whether capacity increases should be allowed formed 

along the same lines as during the development of the RES itself. The environmental community was 

concerned that capacity increases necessarily included additional flow. Lisa Brown from Water Watch 

commented that the key rationale for differentiating between capacity and efficiency was whether the 

16 OAR 330-160-0150 (1). 17 OAR 330-160-0050 (3). 
UM __ - PGE 2012 RPS Compliance Report 

Attachment D 

PageS 

additional increment of energy was based on the same amount of water. 18 Staff agreed that there 

should be no credit for increasing flow. 19 Kate Miller from Oregon Trout suggested utilizing Federal 

Energy Regulatory Commission guidance on this topic, and the language in the rule mimics that guidance 

quite closely. 20 

Because PGE generates additional energy at Faraday from the same amount of water and because the 

improvements completed, rewinding generators, were those specifically called out as eligible 

improvements in OAR 330-160-0050 (1) and in the federal guidance, we believe that OAR 330-160-0050 

(3) is not a bar to the Faraday upgrades qualifying under the RES. The upgrades do not implicate the 

concerns that the environmental community had regarding including capacity increases as eligible for 

generating qualifying electricity. 

Email from Corps to Department Is Not Dispositive and Department Rule Should Be Used To Determine 

Whether Faraday Improvements Generate Qualifying Electricity 

The final issue is the email from the Corps to Julie Peacock at the department. In the email, the Corps 

notes three main issues: First, that the information provided to the Corps through PGE's application 

regarding the upgrades are "limited in scope," and provide "very little opportunity to assess the 

efficiency increases that have been asserted by the utility;" second, that PGE makes use of the term 

uprate "which typically refers to a capacity increase" and that there are limited opportunities for 

efficiency increases of the magnitude that we found at Faraday; and finally, that PGE's method of 

calculating the efficiency increase would "essentially convert a capacity increase into an efficiency 

18 Minutes of RPS 2010 Advisory Committee Meeting #3 

191d. 

20 Minutes of RPS 2010 Advisory Committee Meeting #4 and Renewable Energy Production Tax Credit: Instructions 

for Requesting Certification of Incremental Hydropower Production Pursuant to the Energy Policy Act of 2005, FERC, 

Office of Energy Projects, Division of Hydropower Administration and Compliance. This guidance states in part: 

"We construe 'efficiency improvements' to encompass additional generation from existing equipment in 

the form of upgrades to generators or turbines. Examples include rewinding generators, replacing 

turbines with more efficient units and computerizing control of turbines .... We construe 'additions of 

capacity' to mean any increase in generating capacity other than an addition resulting from an efficiency 

improvement .... " 

Notably, the Energy Policy Act of 2005 on which the guidance is based, allows both efficiency and capacity 

improvements under the banner of "incremental production gains" and authorizes a tax credit for both. This may 

have been a better way to approach the issue and would have avoided having to define something by what it is 

not. 
UM __ - PGE 2012 RPS Compliance Report 

Attachment D 

Page 6 

increase incorrectly, and no information has been provided that would lead [the Corps to] think 

otherwise for the Faraday units." 

However, the department's rule states, in part, that "The determination ofthe percentage increase in 

the efficiency of hydroelectric power production as described in Subsection {1) ofthis rule shall be based 

on the best available evidence." 21 What PGE submitted to the department, and to thus to the Corps, in 

terms of justifiable efficiency numbers was based on "best available evidence." As the email notes, 

"Additional information about the pre-uprate condition of the windings could possibly explain the stated 

5 percent and 8.8 percent efficiency gains." And we agree. PGE bases its claims on the information we 

do have22 and the fact that the law and rules allow the upgrades at Faraday to generate qualifying 

electricity. While an engineer in 1996 may have utilized the term "uprate," it is not important in terms of 

whether these improvements qualify or not. What is important is the language in OAR 330-160-0050 {1), 

and PGE's upgrades meet those requirements: the improvements were to generators and did not 

increase impoundment, appropriation or diversion. 

21 OAR 330-160-0050 (2)(b) 22 We could not have known in 1995 that a flood in 1996 would damage equipment, the repair of which would 

then be the subject of a law adopted in 2007 and a compliance report in 2013, nearly 20 years later, for which data 

from 1995 would be a necessary element. 
-----Original Message-----

UM __ - PGE 2012 RPS Complicance Report 

Attachment E 

Page 1 

From: Shenk, Brian R NWP [mailto:Brian.R.Shenk@usace.army.mil] 

Sent: Tuesday, April23, 2013 3:24PM 

To: Peacock, Julie 

Subject: FW: PGE References (UNCLASSIFIED) 

Classification: UNCLASSIFIED 

Caveats: NONE 

Julie, 

1. I have reviewed the materials provided with regard to the Faraday Units 1-5 generator rewinds. This 

information is limited in scope, and provides very little opportunity to assess the efficiency increases 

that have been asserted by the utility. I have consulted with our Hydroelectric Design Center's (HOC) 

electrical engineers, and they also found the information provided to be too limited in scope. Our 

engineers at HDC are responsible for the largest portfolio of hydropower in the nation, overseeing the 

design work on generating units in a wide variety of vintage, condition, and operating profile. 

2. Paragraph 4) ofthe memo dated April24, 1996 provided by the utility, makes use ofthe term uprate, 

which typically refers to a capacity increase. Generally speaking, most generators are highly efficient, 

allowing for limited opportunities for efficiency increases of more than 0.5 percent. Additional 

information about the pre-up rate condition of the windings could possibly explain the stated 5 percent 

and 8.8 percent efficiency gains. 

3. The final efficiency gains presented by the utility are calculated by dividing post-uprate nameplate 

rating by pre-uprate nameplate rating. This method is unusual. In most cases at most projects, this 

method would essentially convert a capacity increase into an efficiency increase incorrectly, and no 

information has been provided that would lead me think otherwise for the Faraday units. 

Regards, 

Brian 

Brian Shenk 

Chief, Hydropower Analysis Center 

USACE 

Classification: UNCLASSIFIED 

Caveats: NONE 
PGE 2012 RPS Implementation Plan 

Attachment E 
August 11, 2006 

MEMO 

To: Mike Grainey, Director, ODOE 

From: Tom O'Connor, Director, OMEU 

Don Godard, Director, OPUDA 

UM __ - PGE 2012 RPS Complicance Report 

Attachment E 

Page2 

Dick Wanderscheid, Director of the Electric Utility, City of Ashland 

Subject: Draft of Potential RPS Language 

At the conclusion of the July 11 meeting of the Renewable Energy Working 

Group, you asked us to bring our suggestions and ideas to address the issues and concerns 

we have been discussing with you and the REWG regarding a potential Oregon RPS. 

As you know, consumer-owned utilities are governed by our local boards and 

commissions and largely purchase our electricity through federal contracts with BP A. 

Therefore, we believe that any Oregon RPS legislation should have a unique section 

dealing with consumer-owned utilities as is the case generally with federal and state 

legislation. 

Since the July REWG meeting, we have been working to outline what that section 

should look like. Our proposal is described below. We are still working on some of the 

details and will provide those to you as we continue to work with our associations and 

members on this subject. It is also important to recognize that public power is in the 

process of negotiating our future contracts with BP A for a twenty year timeframe post2011. Those contracts and their structure for future resource acquisition to meet load 

growth are critical to the economic health of our communities. 

We believe our proposal accomplishes the Governor's goal to encourage the 

continued development of new renewable resources and reduction of greenhouse gases 

while recognizing the unique nature of consumer-owned utilities, our contractual 

relationship with BP A, and our existing renewable resource development. 

SECTION 

A.) Purposes and Policies: The Legislative Assembly declares that it is the purpose of 

this title to: 

1.) Encourage cost-effective conservation and efficiency in the use of electric 

power; 

2.) Encourage the development of cost-effective renewable resources; 

3.) Assure customers an adequate, economical, and reliable power supply 

4.) Recognize that consumer-owned utilities purchase all or major portions of 

their electricity supply from the Bonneville Power Administration under long-term 

federal contracts; 

5.) Recognize that virtually all of the existing Federal Base System power comes 

from resources that do not contribute to greenhouse gas emissions; 

6.) Recognize that increasing development of renewable resources by consumerowned utilities will require new BP A renewable products, adequate and affordable 

transmission access and the availability of the federal hydropower system and 

conventional resources for shaping and firming; 
UM __ - PGE 2012 RPS Complicance Report 

Attachment E 

Page3 

7.) Preserve and enhance the ability of consumer-owned utilities and their 

governing bodies to respond to their consumers; 

8.) Recognize that communities served by consumer-owned utilities located in 

various parts of the State of Oregon may differ in their needs and desires concerning the 

provision of electricity and related products and services; 

9.) Retain local control over consumer-owned utilities 

10.) Preserve, clarify, and as provided herein, enhance the rights and authorities 

of consumer-owned utilities and their governing bodies. 

B.) Eligible Resources: 

3. Eligible resources include small hydro, solar, wind, biomass, wave/tidal, 

landfill gas, plus -

a.) Hydro efficiency upgrades (including BPA and the Mid-Columbias) 

b.) Tier Two renewable product and renewable portion of any other BP A 

Tier Two product 

c.) Green tags 

d.) Renewables acquired under Tier One 

e.) Verifiable conservation 

f.) Net metered renewable resources 

g.) Combined Heat and Power (CHP) new and upgrades to existing 

facilities 

h.) Resources necessary for integration of new renewable resources 

i.) Small hydro (30 MW or less) 

j.) Eligible biomass should include 50% renewable fuel or waste 

k.) IGCC with sequestration when used as part of a carbon reduction 

program 

4.) Eligible renewable resources and tags include those from within the Western 

Interconnection 

5.) Eligible renewable resources include those brought on line or under contract 

after the effective date of the Northwest Power Act. 

6.) Small, community scale renewable projects (1 0 MW or less) can be counted 

as extra credit (150%) 

C.) All Consumer-owned utilities: 

By 2012, each COU local board, through a public or member process, shall adopt 

and implement a local utility renewable resource policy giving priority to the purposes in 

Section A of this title. 

As part of that policy each COU shall consider and make a specific determination 

whether to implement either: 

1.) inclusion as part of its resource portfolio, in an amount determined by 

the local board, a BP A renewable product, EPP, or other renewable resource, or 

2.) a green pricing or tag program for its customers 
UM _- PGE 2012 RPS Complicance Report 

Attachment E 

Page4 

D.) Consumer-owned utilities over 50,000 customers: 

By 2012, each local board for a COU over 50,000 customers upon enactment, 

through a public process, shall adopt and implement a local renewable resource standard 

giving priority to the purposes in Section A of this title. 

A local renewable resource standard is deemed to meet the intent of this title if it 

targets either: 

1.) 25% ofload with eligible renewables by 2025 or 

2.) 60% ofload growth with eligible renewables by 2025 

Adoption of a local alternative standard to (1.) or (2.) must be accompanied with 

findings and a determination that the standard is consistent with Section A of this title. 

The board may adjust the standard if it determines through a public process and 

with appropriate findings that one or more of the conditions in Section E.) apply. 

F.) Annual Report: 

Annual report to ODOE acknowledging compliance- report only- no new 

regulatory authority 

E.) Provisions that apply to all COUs: 

1.) Specific clause that says nothing in this act shall cause a utility to reduce the 

amount of load served by BP A from the federal base system including but not limited to 

Tier One. No utility shall be required to forgo any generating resources owned or under 

contract as of the date of this Act nor to acquire any resource or credits that would cause 

the utility to have resources or credits in excess of the cumulative electric demand of its 

customers. 

2.) Statutory cost cap- cap includes transmission and ancillary services, 

integration, R&D, and dry hole costs associated with renewable resource and is triggered 

through certification by COU board through public process 

3.) Off ramp for force majuere 

4.) Off ramp for lack of transmission availability 

H.) Placeholder for statutory changes that may be necessary for COUs to 

implement the above requirements and policies. 

(For example, ensure that COUs have the appropriate financing and legal tools) 
UM __ - PGE 2012 RPS Complicance Report 

Attachment E 

PageS 

My name is John Carstensen, I am the Thermal Project Manager for the Idaho Power 

Company. Idaho Power is a 10% owner of the Boardman Power Plant. 

Of the approximately 90,000 lbs of mercury emitted each year from coal fired utilities in 

the US, almost 92% is emitted by Eastern utilities. Boardman emits approximately 200 

lbs/year, about 1/4th of 1% of the mercury emitted by U.S. coal fired utilities. The Idaho 

Statesman reported on Monday of this week that there is a cement plant in Eastern 

Oregon that emits over 2,100 lbs of mercury each year, about 10 times the emissions of 

Boardman. 

Because of the low levels of mercury in the coal burned at Boardman, precise 

measurement is difficult at best. Controlling or reducing mercury emissions at Boardman 

will be even harder. No proven and available retrofit control technology exists to reduce 

mercury to the proposed 0.6lb/TBtu on existing pulverized coal fired utility boilers. 

The Federal EPA cap and trade program that has been so successful for S02 was adopted 

for mercury. The huge success of this program lead to over-compliance by utilities. For 

mercury, the EPA established the cap and trade program to effectively reduce mercury 

emissions while allowing utilities to determine the most cost effective means. By 

replacing the cap and trade program to command and control, Oregon will lose all of the 

cost benefits designed into this program. 

Striving to make Oregon a model state and proposing to pass the most stringent 

requirements for mercury emissions may sound noble, but one must ask "is it really 

required to achieve the necessary goals?" Nothing comes without a cost and the costs of 

these changes must be considered fully rather than ignored. 

By basing limitations of emissions on emotion, unnecessary costs and burdens will be 

placed on businesses and especially on the customers least able to pay the utility bills. 

Therefore it is our position that the DEQ should use sound judgment and proven science 

to determine the regulations to control mercury from Boardman. 

Thank you for your time. 
UM __ - PGE 2012 RPS Complicance Report 

Attachment E 

Page6 

September 6, 2006 

To: Mike Grainey and Bill Drumheller 

From: Tom O'Connor 

Subject: Draft of Potential RPS Language 

Below is a more fleshed out version of the outline Don, Dick and I submitted to 

the August REWG meeting. This has not been reviewed by legal counsel, but I've 

attempted to put our thoughts on a public power section into legislative style and format. 

I hope this will be helpful as you draft your strawman. 

SEC. 1. Purposes and Policies: The Legislative Assembly declares that it is the 

purpose of this Act to: 

1.) Encourage cost-effective conservation and efficiency in the use of electric 

power; 

2.) Encourage the development of cost-effective renewable resources; 

3.) Assure customers an adequate, economical, and reliable power supply 

4.) Recognize that consumer-owned utilities purchase all or major portions of 

their electricity supply from the Bonneville Power Administration under long-term 

federal contracts; 

5.) RecogniZe that virtually all of the existing Federal Base System power comes 

from resources that do not contribute to greenhouse gas emissions; 

6.) Recognize that increasing development of renewable resources by consumerowned utilities will require new Bonneville Power Administration renewable products, 

adequate and affordable transmission access and the availability of the Federal 

hydropower system and conventional resources for shaping and firming; 

7.) Preserve and enhance the ability of consumer-owned utilities and their 

governing bodies to respond to their consumers; 

· 8.) Recognize that areas served by consumer-owned utilities located in various 

parts of the State of Oregon differ in their needs and desires concerning the provision of 

electricity and related products and services; 

9.) Retain local control over consumer-owned utilities 

10.) Preserve, clarify, and as provided herein, enhance the rights and authorities 

of consumer-owned utilities and their governing bodies. 

SEC. 2. Definitions 

1.) "Consumer-owned utility" means a municipal electric utility, a people's 

utility district or an electric co-operative as defmed in ORS 757.600. 

2.) "Covered consumer-owned utility" means a consumer-owned utility that 

serves over 50,000 retail electric customers in Oregon on the date of this Act. 

3.) "Eligible renewable resource" means 

(a.) electricity from a generating facility powered by a renewable resource 

that commenced operation after the passage of the Regional Act where the facility 

is located within the boundaries of the Western Energy Coordinating Council 

(b.) incremental electricity produced as a result of improvements to 

existing hydroelectric generation or combined heat and power projects owned or 
UM - PGE 2012 RPS Complicance Report 

operated by a utility, the federal government, or any other entity within the 

boundaries of the Western Energy Coordinating Council.. 

Attachment E 

Page7 

(c.) electricity from hydroelectric generating facilities 30 MW or less 

(d.) electricity from eligible renewable resources purchased from the 

Bonneville Power Administration 

(e.) electricity needed to shape, firm, or integrate an eligible renewable 

resource used to meet the requirements of Section 3 and 4 of this Act 

(f.) electricity from a customer-owned eligible renewable resource through 

a net metering agreement or PURP A contract 

(g.) renewable energy certificates or green tags from eligible renewable 

resources . 

(h.) renewable resource research and development expenditures 

(i.) community scale projects eligible at 150% credit 

4.) "Renewable resource" means (a.) wind; (b.) solar; (c.) geothermal; (d.) water; 

(e.) wave, ocean, or tidal power; (f..) verifiable conservation; (g.) combined heat and 

power (CHP); (h.) biomass energy from landfill gas, wastewater treatment facilities, 

animal waste, and solid organic fuels from wood, forest or field residues or dedicated 

energy crops or black liquor but does not include wood products treated with chemical 

preservatives or municipal solid waste. 

SEC. 3. Consumer-owned utility renewable resource policies 

1.) By 2012, each local consumer-owned utility board, through a public or 

member process, shall adopt and implement a local utility renewable resource policy 

giving priority to the purposes in Section 1 of this Act. 

2.) As part of that policy each consumer-owned utility shall consider and 

make a specific determination whether to implement either: 

a.) inclusion as part of its resource portfolio, in an amount determined by 

the local board, a BPA renewable product, or other eligible renewable resources, 

or 

b.) a green pricing or green tag program for its customers 

SEC. 4. Covered consumer-·owned utilities to adopt renewable resource standards 

1.) By 2012, each local board for a covered consumer-owned utility, through a 

public or member process, shall adopt and implement a local renewable resource standard 

giving priority to the purposes in Section 1 ofthis Act. 

2.) A local renewable resource standard is deemed to meet the intent of Section 1 

if it targets either: . 

a.) 25% of load with eligible renewable resources by 2025 or 

b.) 60% of load growth with eligible renewable resources by 2025 

3.) A covered consumer-owned utility may adopt a local alternative standard to 

Subsection (2.)(a.) or (b.). The local alternative standard must be accompanied with 

findings and a determination that the standard that is consistent with Section 1 of this Act. 

4.) The board may adjust the standard if it determines through _a public or 

member process and with appropriate findings that there is a lack of firm transmission 

availability to acquire renewable resources needed to meet the standard or that the 

standard cannot be met due to a force majeure event. 
SEC. 5. Resource costs 

UM __ - PGE 2012 RPS Complicance Report 

Attachment E 

PageS 

1.) Placeholder for cost cap which must be included in any RPS 

2.) Nothing in this Act shall cause a consumer-owned utility to reduce its 

purchases of the lowest priced electricity from the Bonneville Power Administration 

pursuant to Section 5 of the Pacific Northwest Electric Power and Conservation Act of 

1980, Public Law 96;.501, as amended. 

3.) Nothing in this Act shall require a consumer-owned utility to forgo any 

generating resources owned or under contract as.ofthe date of this Act nor to acquire any 

resource or credits that would cause the utility to have resources or credits in excess of 

the cumulative electric demand of its customers. 

SEC. 6. Annual report to Oregon Department of Energy 

1.) Each consumer-owned utility shall submit an annual statement to the Oregon 

Department of Energy that verifies it is in compliance with this Act. The statement 

submitted by the consumer-owned utility is for informational purposes and is not subject 

to approval by the Oregon Department ofEnergy. 

SEC. 7. Existing rights and authorities of consumer-owned utilities 

1.) Nothing in this Act is intended to limit or restrict the rights and authority of a 

consumer-owned utility, or to subject a consumer-owned utility to the regulatory 

authority of the Public Utility Commission not otherwise provided by law. 

SEC. 8. Placeholder for statutory changes that may be necessary for CO Us to 

implement the above requirements and policies 
UM __ - PGE 2012 RPS Complicance Report 

Attachment E 

Page9 
September 7, 2006 

TO: Mike McArthur, Bill Drumheller 

FROM: RPS Discussion Group 

Dear Mike: 

UM __ - PGE 2012 RPS Complictt?c,e Jl.e~ort 

Attat.hkVnt E 

Page 10 

We are a group of consumer advocates, utilities, developers, and enviromnental groups 

that are members of the Renewable Energy Working Group (REWG) that you chair. As 

you are aware, we have had many discussions regarding the details of a Renewable 

Portfolio Standard (RPS) in Oregon. Our intent with this document is submit to the 

REWG, for its September 13th meeting in Hood River, the following issues for inclusion 

in the RPS that the Oregon Department of Energy is drafting. 

This document is broken down into two sections. The first section features issues where 

there is agreement and the second features unresolved issues where the parties have 

different approaches and there is not yet consensus. We hope that this information will 

contribute to the discussion on September 13th regarding what the draft RPS should look 

like. 

I. ISSUES AGREED UPON 

A. Defmitions 

"Load" means the amount ofkilowatt-hours of electricity that a qualifying utility 

delivered to its Oregon retail customers in the most recently completed year. 

"Non-power attributes" means all enviromnentally related characteristics, exclusive of 

energy, capacity reliability, and other electrical power service attributes, that are 

associated with the generation of electricity from a renewable resource, including but not 

limited to the facility's fuel type, geographic location, vintage, qualification as an eligible 

renewable resource, and avoided emissions of pollutants to the air, soil, or water, and 

avoided emissions of carbon dioxide and other greenhouse gases. 

"Pacific Northwest" has the same meaning as defmed for the Bonneville Power 

Administration in section 3 of the Pacific Northwest electric power planning and 

conservation act (94 Stat. 2698; 16 U.S.C. 20 Sec. 839a). 

"Bundled" means when electricity generated from eligible renewable resources is 

accompanied by its non-power attributes. If a qualifying utility buys both the electricity 

and the associated RECs from a qualifying resource, the power and RECs are considered 

bundled. 

"Unbundled" means separating electricity generated from eligible renewable resources 

from it's accompanying non-power attributes. If a qualifying utility buys only electricity 

or RECs, but not both, from a qualifying resource, the power and REC are considered 
UM __ - PGE 2012 RPS Complicance Report 

Attachment E 

Page 11 

unbundled. Unbundled does not refer to separating out specific non-power attributes 

such as avoided emissions of carbon dioxide, mercury, nitrous oxide, sulfur dioxide, etc 

"Renewable energy credit" means a tradable certificate of proof of at least one 

megawatt-hour of an eligible renewable resource where: the certificate includes all of the 

non-power attributes associated with that one megawatt-hour of electricity and the 

certificate is verified by a renewable energy credit tracking system selected by the 

commission. 

"Renewable Resource" 

There is general agreement that "renewable resource" means an owned or contracted 

for: (a) solar energy; (b) wind energy; (c) geothermal energy; (d) landfill gas; (e) wave, 

ocean, or tidal power; (f) gas from sewage treatment facilities; (g) fuel cells using only 

eligible renewable resources; (h) biomass energy based on animal waste or solid organic 

fuels from wood, forest, or field residues, or dedicated energy crops that do not include 

( 1) wood pieces that have been treated with chemical preservatives such as creosote, 

pentachlorophenol, or copper-chrome-arsenic; or (2) municipal solid waste. Fossil fuels, 

nuclear fuels, or their derivatives are not eligible renewable resources. 

"Delivered" and "Delivery" mean the output of a renewable electricity generation 

facility that is generated at a location either 1) within the state or 2) out of state, but 

delivered to a qualifying entity's transmission system or contracted point of receipt. 

B. Issues 

f_(l~l)!_l11lliJ~¥C:_~_I)lig!~!llJ~-~I)_et~~-l11l~~r4 _________________________________________________________ _ 

Each qualifying utility ."Y. il! _u_se 11l1n.~l~<:l_or_l!fi.b)lll.<:ll_e~ -~~~ _fr()!ll_ ~U ~ligi!Jl~ re11e_'\V~bl_e 

resource to meet the standard. Unbundled RECs used for compliance ,.s_a1~ _<_:~~e_ fro~ ____ _ 

eligible renewable resources located in the Pacific Northwest. For RECs from eligible 

renewable resources outside of the Pacific Northwest, both the power and RECs must be 

bundled and delivered to the qualifying entity. Each-renewable energy credit may count 

only once towards either the requirements of an Oregon renewable portfolio standard or 

toward another state's renewable portfolio standard. 

Unbundled electricity from eligible renewable resources shall not be counted toward the 

standard. 

Renewable energy or RECs sold to customers through a retail premium-priced renewable 

energy tariff shall not be counted toward compliance with this rule. 

A qualifying utility rna y not resell renewable energy credits and count those sold credits 

toward the utility's obligation to meet this standard. 

Cost Recovery 

An investor-owned utility is entitled to recover in rates all prudently incurred costs 

associated with compliance of this standard. A public utility shall also recover its 

Deleted: Geographic eligibility- the 

Pacific Northwest</ 

Formatted: Font: Bold 

[Deleted:. 

( Deleted: shall 

[ Deleted: must 
UM __ - PGE 2012 RPS Complicance Report 

Attachment E 

Page 12 

reasonable interconnection and transmission costs required to deliver renewable energy to 

retail customers in Oregon. 

Protect Consumer-Owned Utilities' Access to BPA Tier I Resources 

It is agreed that nothing in this RPS should require consumer-owned utilities to forego 

access to BPA's as-yet-defmed Tier I product (i.e., affordable hydro). 

Cost Cap 

.'fht)re)~ -~gr~-~!11:~~! .!lJ:at_~~-~-~- sl).~~~~-~~~_1-~~~- ~~~~-~~~t~f ~~~!.~~P:. )~. ~~-~!~~-~Z!~~~- ______ ... -· {>=o~e~le~te~d~: =======~ 

that fll:l.~~!at~~~~_f~:t; _ ~-~t~n~IlJ~J!!g _t_ht) -~RP.l_i_~!!_~_l~ -~!!1~1:1.1!~. ~f_~~~y-~ _ r~~~r_l~~~ -~~~!?.!~ _ ~-~ ____________ ... -- · ~~.'.!_: cost cap 

counted towards the cost cap include those costs that make the two resources comparable 

on a delivered basis,. [ls it fair to sav here that we had consensus on that fact that the cost __ .. ---- 1

~ Deleted: both a renewable resource and 1• 

can should adjust withci1anges "iii" tiie.baseillle"?l""itowever,"here"is "8iiifciisagr"• "eemeiii"()D.""". a non-renewable compamtor should 1 = · - - include all costs associated witlt ' 

how exactly the cost cap should be structured. The cost cap is not a hard cap, per se, but delivering tlte electricity including : 

is a fmancial cap which a qualified entity is not obligated to exceed, but may do so and \ integmtion and transmission. ___ ! 

must subsequently make a case for rate recovery showing that those additional 

expenditures were prudently incurred. (Some options are presented below) 

II. UNRESOLVED ISSUES 

Below are questions that remain regarding several critical issues. We hope that these can 

be discussed at the REWG meeting on September 13th. 

Defining Renewable Resource 

-7 Unresolved issues: 

Biomass: 

Questions still remain about whether to include (a) black liquor byproduct 

from paper production and (b) woody biomass from old growth forests 

among eligible biomass resources. 

Hydro: 

Remaining hydro issues to resolve: (1) low-impact, small hydro- what 

should the size limit be and should only small hydro that is certified as 

low-impact be eligible? 

(2) Can utilities count only incremental improvements at existing 

hydroelectric facilities that they own or can they count their portion of 

upgrades at a contracted hydro resource? What about counting RECs 

from hydro upgrades? 

Date of eligible renewable resource 

Ifthe RPS is to include as a gualitied renewable resource a limited number of existing 

resources it is necessary to determine the cutoff date for this dete1mination . .__ _____________________ .. --~ ~e_l1~~ed: It i

1

s_ c_nb'111'cal tdofrodecidhe wh~ch 

1act tties are e tgt e an m ow tar 

th , . , back. Tite greater the amowtt of existing . 

At the August 15 REWG meeting, two dates were proposed: 1) drawmg the lme at facilitiesthatareeligibleunderanRPS, I 

1998 to capture the region's first new utility-scale renewable facilities (Vansycle wind tlle Jessnewrenewableresources will _,1 

L".ome on hne._c,:._____ _ 
UM __ - PGE 2012 RPS Complicance Report 

Attachment E 

Page 13 

project in OR and Foote Creek in WY) and 2) going back to 1981 to coincide with the 

NW Power Act. 

The following is as an illustration of how existing resource might impact the 25% RPS. 

(These are based on the Northwest Power and Conservation Council figures at 

http:/ /www.nwcouncil.org/energy/powersupply/existingprojects.xls.) 

RNP,(!S~~~_t_e~_th!!:t~!~.9~_a_v~~!l:g~MW.~!~-~~~~.<?~-~<?-~~-<?!.!~<?J?;<?_~~-<?_f_~-?~-~-~-~--------·-{ __ -D_e_le_te_d_:_w_e _______ . 

by 2025. The total of all existing large and small hydro, black liquor, wood-fired, 

biogas, wind and geothermal plants in the northwest back to 1981 equals 1,468 

aMW. This means that 67.3% of the 25% RPS goal could be met by purchasing 

green tags from these preexisting resources . The total amount of these same 

facilities back to 1998 equals 639 aMW, or 30.4% of the total2,100 aMW. 

Cost Cap 

Several options were discussed as to what base to apply a cost cap percentage target to. 

One is to have the cost capJ2~1:~_c:n_tage_t(lrget_(}P1?1)1 _to_tll(': _qtt~_lif'i_e~_ut@jt:~.!()ta!_r(':y_~~ll.(!m_.------{ Deleted: setatXo/oofa ~ 

requirement_l}n<i_all(Jth_er_js_t()_liPRJ:tt_~~-C()St_C:_~P,_p_~rc;~~!a_g~_to_!.()tai_R()~~~r-~()~-~~~HA<?!'!:! _____ .-----~ted:. Anotlter 

recall that the ACP wa~ a cost cap but a substitute for cost effe-ctiveness stam!ard] 

Another comQonent of the congmt of cost cap that was discussed but not resolved was 

should there be a "cost effectiveness" standard underneath a cost cap. 111e concept here 

is should any single resource acquisition decision be constrained by not exceeding l}._set 

percentage over the costs of its cost cap comparable. 

In addition, should investments in emerging generation technology and/or energy 

efficiency be counted toward~ the cost cap? 

Regarding what should be the targeted cost cap percentage no consensus has been 

reached at this tin1e given the fact that too many other components of the RPS standard 

have not been settled~---m• .... uuum.mmu,........... - u .. - uuuum .... m• 

Banking of RECs 

Several proposals regarding the vintage of eligible RECs have been discussed: 

1) For any given year the requirements may be met with RECs produced during that year, 

the preceding year, or the following year. 

2) RECs from any eligible renewable resource may be traded or banked, but in an effort 

to encourage early action, a qualifying entity must surrender the oldest RECs first in 

subsequent compliance filings (i.e., 'First-in-First-Out'). 

3) For any given year the requirements may be met with unbundled RECs produced 

during that year, the preceding year, or the following year. Additionally, bundled RECs 

from any renewable resource may be banked and used to meet subsequent compliance 

requirements, but a qualifying entity must surrender the oldest RECs first in subsequent 

compliance filings (i.e., 'First-in-First-Out'). 

. -- f Deleted: to use an Alternative 

Compliance Payment as a cost cap. 
UM __ - PGE 2012 RPS Complicance Report 

Attachment E 

Page 14 

Interim Targets 

While the 25% by 2025 would remain set, there are several proposals for how to --·-··----·---· -----.. 

determine the interim tai:gets. They are: JE~_l_l_f!.Y.~_!1_()j~~~l:~T?_l_h~:i:9J.<!~!?;~~~-'-~.<?J1_':\Xe_,<?!1_~------- ... ------{ Delete~: One option i_s ___ _ 

interim midway hard target, to have only two interim targets that would be rigid in that 

the PUC would not be allowed to adjust the targets. Another option is to have three or 

four interim targets but to allow flexibility so that the PUC could adjust them if needed. 

[Troy: should ACP be mentioned here?] 

Utility Eligibility 

"Qualifying Entity" 

Regarding whom is a qualified entitv there are three schools of thought. First is be all 

inclusive of all retail energv service providers (including energy service suppliers and 

direct service industrial customers), second to set a threshold that qualifies only those 

entities that meet this threshold and third to set a threshold to qualifies only those that 

meet the threshold be requires a lesser standard for those that didn't.~-----------------------···----------­

~ Additional issue: 

What is the right threshold for determining utility eligibility? 

PURPA Qualifying Facilities 

There is a critical question regarding how to treat RECs from PURP A facilities. 

Deleted: nteans (i} a utility serving ! 

retail customers in Oregon with an annual I 

electric load of[XX] average megawatts ! 

I or more; (ii} auy electric service supplier i I serving direct access customers in l 

Oregon; and (iii} any direct service ) 

industrial customer in Or~gou. ____ ) 

I ~;;:;~~~- ~~~~~~~;-~: .. ~q~;~~;-~~~~~~-~ ~;~~r~s:_:~~;;~;e~~~~!~oi;~~~~ -~()_: ... ___ .- · Deleted: because tltey are not allowed 

PURP A project, this is a conflict and there is currently no way for a utility to count a ;:::

1

=0 p=a=y========~ 

REC from a QF toward RPS compliance .• T.~_s __ ~~()~~~ -~-~ _ ~~~e_s~-~~-~~t~~r -~ ~~_:~zys_ _ot: _ ..... _. --- {~o_e_le_te_d_: ______ _____~ 

in accompanying legislation. 

One proposal would allow a regulated utility to have frrst right of refusal on purchasing 

any RECs from a OF, as long as the avoided cost paid by the utility is adjusted to reflect 

the avoided cost the utility would have otherwise incurred purchasing bundled renewable 

electricity. 
UM __ - PGE 2012 RPS Complicance Report 

Attachment E 

Page 15 

DRAFT -Do Not Quote or Cite-- DRAFT September 12, 2006 DRAFT 

Oregon Draft RPS and Related Policy Legislative Package Outline 

DISCLAIMER: This is a conceptual outline focusing on the structure, mechanics, and 

"ingredients" of a potential broad-based RPS policy with related renewable energy measures that 

are necessary complements to the RPS. The language used in this summary is not intended to be 

"bill language" and, in many cases, more work needs to be done to produce precise terminology. 

Fundamental Architecture 

Key Point 

All utilities are subject to a renewable energy standard, but the smallest utilities only need 

concern themselves with load growth. No public utility will lose its BPA Tier I rights. 

Basis of Compliance with the RPS will be measured in energy units of total sales to retail 

Compliance customers in Megawatt-hours (MWh) 

Compliance Tradable Renewable Energy Certificates in units of one (1) Megawatt-hour ( MWh) 

Mechanism 

Structure One tier with new and some existing facilities serving Oregon load eligible, but with 

primary and secondary RPS requirements depending on percentage of load served. 

Tier I Power No utility shall be required to lose its rights to Tier I BP A power through the RPS. 

Primary RPS Standard t,u~fJ Ct+Ys (hrft} 

PrimaryRPS All utilities and energy service providers that ate responsible for one (1) percent or 

Applicability greater of total retail electric sales in the State of Oregon (as measured by percent of 

Threshold MWh sales) are subject to the Primary RPS requirements as follows: 

End Target 25 percent of retail load by 2025 and each year thereafter 

Interim Targets 15 percent of retail load by 2015 and each year thereafter until 2020 

20 percent of retail load by 2020 and each year thereafter unti12025 

Secondary RPS Standard 

Secondary RPS All utilities and energy service providers in Oregon that do not fall under the 

Policy Threshold Primary RPS must meet the requirements of a Secondary RPS as follows: 

End Target 60 percent of retail load growth by 2025 and each year thereafter 

Interim Targets 20 percent of retail load growth by 20 15 and each year thereafter until 2020 

40 percent of retail load growth by 2020 and each year thereafter until 2025 
UM __ - PGE 2012 RPS Complicance Report 

Attachment E 

Page 16 

DRAFT -Do Not Quote or Cite-- DRAFT September 12, 2006 DRAFT 

Qualifying Renewable Resources 

Key Point 

Given Oregon's diversity of renewable resources the list of resources that qualify for the 

RPS is on the generous side, including incremental improvements to existing facilities. 

Electricity Wind 

Derived From: Solar photovoltaic and solar thermal generation 

Wave, tidal, and ocean thermal 

Geothermal 

Biogas from organic sources, wastewater, anaerobic digesters, or landfills. 

Biomass as per the definitions agreed to by the "RPS Discussion Group", but 

explicitly including spent pulping liquor 

Incremental output of non-hydro generation units using qualifying renewable 

sources that have demonstrably increased generation in excess of 10 percent using 

eligible renewable resources through capital investments made after the enactment 

of this RPS. 

Hydropower as defined by SB 1149 

The increment of improvement resulting from efficiency upgrades to an existing 

hydropower facility of any size, including those on the BPA system. 

Biodiesel (99.9%+ blend or pure) not derived from palm oil, from lands cleared of 

old-growth forests, or from first-growth forests cleared after the RPS start date. 

The incremental renewable energy proportion of a multi-fuel generation process. 

Hydrogen that is reformed from or electrolyzed entirely from the qualifying 

renewable resources listed above. 

Qualifying Subject to the geographic constraints noted below, qualifying facilities are those 

Facilities using qualifying renewable resources that were (1) operational on or after January 1, 

1995 and are either {i) located in Oregon or {ii) have been serving Oregon load for at 

least 50% of their operational life; or are (2) facilities using qualifying renewable 

resources that become operational after the enactment date of the RPS. 

BundledREC Qualifying facilities that generate renewable electricity sold to affected entities with 

Geographic the associated RECs (bundled RECs) from qualifying renewable resources must be 

Eligibility (a) physically located in Oregon or {b) located outside of Oregon but delivering 

power to an affected entity's transmission system or its contracted point of receipt. 

Unbundled REC RECs that have been unbundled from their associated electricity must derive from 

Geographic facilities that are physica1ly located within the Pacific Northwest region as defined 

Eligibility by the Northwest Power Planning and Conservation Act, or those parts of California 

and Nevada that fall within the service territory of affected entities. 

Packaged Products Procurement of bundled RECs as part of "packaged" products (e.g., "shaped" power 

(e.g., "firmed" or BPA EPP) is permissible but only the proportion of resources in that "package" 

resources) that are qualifying renewable resources will count toward compliance with the RPS. 

BPAEPP or If a BP A decision on the resource mix of EPP product or its equivalent results in a 

Substantially mix that includes resources not listed above a determination may be made by the 

Similar Product Oregon Department of Energy to apply an appropriate deflator to the BPA product. 

2 
UM __ - PGE 2012 RPS Complicance Report 

Attachment E 

Page 17 

DRAFT -Do Not Quote or Cite-- DRAFT September 12,2006 DRAFT 

Voluntary Renewable Energy Tariff Programs 

Key Point 

All Oregonians should be able to voluntarily purchase renewable energy if they so 

choose, although those purchases should not count towards the mandatory requirements. 

Mandatory All utilities and energy service suppliers will be required to offer a voluntary green 

Program power purchasing program to their customers (similar to Washington statute). 

Use of Voluntary RECs and/or renewable energy procured by affected entities and used to satisfy 

Green Energy voluntary customer green pricing tariff programs are not eligible for compliance 

with the RPS. /.':(1;1 Purchases in RPS . if J, v1 

ill/ v 

c ~: ~-'j-~rLJ""(l v~o¥·~'{nt'Vf r-Y1 .. '( 

BP A Tier I Power Exemption "" ~,., Ci~ ~~ .t. '{/ rr ,.,~{-J 

c:"'fft 'lbv'l . i ~ v 

Key Point ./ '{}!.~ {!!fir (,) 11'1' " 

There is broad consensus that the publics should not lose their Tier I ~r entitlements. li ' 

/ 

Exemption Scope All utilities that receive BPA Tier I preference power. r' 

RPS Calculation The total load of an affected entity should be used in determining the required 

Modifications portion of load that must meet the RPS for a given target year. However, any part 

of that load portion that would displace BPA Tier I power should be eliminated 

from the requirements of the RPS for that affected entity on a one-for-one unit 

basis. For example, 3 percentage points ofRPS-applicable load are Tier I so the 

requirement for that affected entity would be, say, 25- 3 = 22 percent in 2025. 

Renewable Energy Certificates 

Key Point 

Allowing the use of renewable energy certificates provides necessary flexibility to 

affected entities in complying with the RPS. A reasonable cap on the use of unbundled 

RECs is helpful in encouraging long-term policy stability and encouraging development 

of new renewable energy resources in the region. A long-term contracting standard is an 

effective means to push RPS costs lower and helps to minimize the need for interim 

targets since resources will be locked in between compliance years. 

Verification RECs used for compliance must be certified by the WREGIS or its successor 

organization, or another tracking mechanism designated jointly through consensus 

bv the Oregon PUC and the Oregon Department of Energy. 

Unbundled REC No more than 20 percent of an affected entity's compliance in a given compliance 

Upper Limit year for the Primary RPS Standard can be met through the use of unbundled RECs, 

with the excej)tion ofRECs from qualifying customer-sited or off-grid facilities. 

3 
UM __ - PGE 2012 RPS Complicance Report 

Attachment E 

Page 18 

DRAFT -Do Not Quote or Cite-- DRAFT September 12, 2006 DRAFT 

RECsfrom Affected entities may satisfY the requirements of the RPS with generation owned 

Facilities Owned by the affected entity to the extent that the RECs generated from that power are 

by Affected kept and retired by the affected entity (and the RECs must be WREGIS certified). 

Entities 

Contracting Affected entities that procure RECs from another party to comply with the 

Standard for RECs Primary RPS requirements, with or without the associated power, must acquire 

those RECs under long-term contracts of at least 15 years in duration. 

No Double- RECs used for compliance with the Oregon RPS must be used solely for the 

Counting of RECs Oregon RPS and can not be used for compliance with any other state's RPS. 

No Disaggregation RECs used for compliance with the RPS must include all environmental attributes 

ofRECs associated with that REC from its inception. No environmental, emissions, or 

other characteristic or attribute of the REC may be stripped out and traded, sold, or 

otherwise used for any other compliance system or attribute financial market. 

RECsfrom This issue needs more investigation before language (if any) is added to the RPS. 

PURPAQF's 

Off-grid and RECs from customer-sited and off-grid qualifying renewable resources located 

Customer-sited within the State of Oregon are eligible for compliance with RPS as long as they 

Resources meet the verification procedures and submittal processes set forth by the WREGIS 

Oj)_erational rules. 

Resource Diversity 

Key Point 

RPS policies do not inherently encourage resource diversity. Rather than having a "carve 

out" in the RPS, the public purpose charge will instead be re-focused solely on assisting 

those resources which would otherwise be at a disadvantage under the RPS policy. 

Set-asides or There are no specific percentage procurement requirements for specific resources 

"Carve Outs" or resource types within the RPS, premised on substantive changes to the PPC. 

Renewable Energy Focus the renewable energy portion of the Public Purpose Charge (PPC) on 

Component of the funding a mix of community projects of20 MW or less and exclude funding of 

Public Purpose projects larger than 20 MW. Require as part of this statute that the OPUC will 

Charge ensure that implementation ofPPC programs reflects this change in focus. 

Community-Level Direct the OPUC, ODOE, ODA, ODF, OECD, and other relevant state agencies to 

Renewable Energy consider community-based renewable energy projects as critical elements of 

Goal Oregon's energy policies. Furthermore, these agencies are to support the 

development of these projects by establishing or modifying procedures and 

policies as necessary in order to achieve a goal ofhaving at least 8% of Oregon's 

electrical retail load come from a mix of community renewables by 2025. 

4 
UM __ - PGE 2012 RPS Complicance Report 

Attachment E 

Page 19 

DRAFT -Do Not Quote or Cite-- DRAFT September 12,2006 DRAFT 

Compliance Standards 

Key Point 

Only two interim "hard" targets are used to ensure progress, so un:erecedented flexibility 

is granted to utilities to reach the final target. However, progress reporting is required. 

Compliance Submittal of WREGIS certified RECs which are subsequently retired in order to 

Method demonstrate compliance for each affected entity with the RPS. 

REC Retirement When complying with the RPS the oldest vintage RECs must be surrendered and 

retired by an affected entity before newer RECs are used for RPS compliance. 

Reporting Bodies For the IOUs: Oregon Public Utility Commission 

For the CO Us: Oregon Department of Energy 

"Hard" targets The first calendar year for which each interim target begins, and the year in which 

the final target occurs and each year thereafter, shall each be considered a 

compliance year for which compliance to the RPS must be demonstrated in full by 

affected entities and for which mandatory enforcement provisions will exist. 

"Hard" Target Between 12 to 15 months after the compliance year a determination shall be made 

Compliance by the reporting body as to whether compliance with the RPS has been met or not 

Determination by each affected entity for that compliance year. 

"Soft" Targets Each affected entity must submit a progress report every two years demonstrating 

current and future plans to meet the requirements of the RPS, with specific 

renewable energy targets set by the affected entity for each year between and 

before the interim targets. (Should be timed with IRP cycles somehow.) 

"Soft" Target The progress report submitted by each affected entity will be scrutinized by the 

Adequacy appropriate reporting body and a determination will be made as to whether the 

Determination report and the acquisition targets within the plan are adequate or not. 

Rolling Average Compliance with the RPS will be determined using a rolling average for each 

compliance year. The total of the RECs acquired for compliance with the RPS for 

a given compliance year will be figured by taking the total of the year before the 

compliance year, the total of the compliance year, and the total of the year after 

the compliance year. Those three years are then averaged for a one-year average. 

Grace Period RECs for a compliance year must be purchased and retired within 90 days of the 

end of the compliance year for which the RECs are intended to satisfy. 

Flexibility Mechanisms 

Banking I Accrual of RECs generated in a given year, but in excess of the target for the 

given year, can be banked and held for a period of up to five years before use. 

-- Borrowing I No borrowing from future generation is allowed. Only banked RECs can be 

added to the mix computation in lieu of actually procuring RECs for a given year. 

5 
UM __ - PGE 2012 RPS Complicance Report 

Attachment E 

Page 20 

DRAFT -Do Not Quote or Cite-- DRAFT September 12,2006 DRAFT 

Cost Recovery 

Key Point 

Providing a profit incentive is a newer concept with RPS, but is consistent with past 

precedent in energy efficiency regulation. Colorado has implemented this in their RPS. 

Recovery All prudently incurred costs are recoverable, including those associated with 

Standard (for transmission and delivery ofrenewable energy to customers in Oregon. 

IOUs) 

Market Include assurance language that money spent on market transformation activities 

Transformation for early-stage renewables (e.g., wave energy) will be eventually recoverable. 

Profit Incentive Utilities may earn an extra profit on their investment in renewable energy if these 

investments provide net economic benefits to customers as' determined by the 

OPUC, with the bonus limited to twenty-five percent ofthe net economic benefit. 

(assumed to be substantially similar to Colorado, see 4 CCR 723-3 3660 (d)) 

Cost Cap for Investor-Owned Utilities 

Key Point 

The Cost Cap Discussion Group is still discussing the structure and mechanics of the IOU 

cost cap, with the.possibility of further discussion before bill language is drawn up. 

Cost Cap Three options have been discussed: 

Mechanism 1) A limit on the percentage increase in the total revenue requirement or total 

power costs. 

2) A resource vs. resource comparison on a case per case basis. 

3) An alternative compliance payment indexed to (for example) twice the average 

REC price of the previous year, or multiple years 

Cost Cap Limit Proposed to be left blank in the draft legislation 

Cost Cap for Consumer-Owned Utilities 

Key Point 

The alternative compliance payment (ACP) mechanism provides a de facto cost cap, 

avoids the thorny issue of penalties for COUs, and has a good BPA price referent. 

Cost Cap An alternative compliance payment (ACP) must be paid if compliance with RPS 

Mechanism requirement through procurement of RECs is not achieved by the affected entity. 

ACP Cost Level The ACP will be indexed slightly higher than the price of the BP A renewable Tier 

Determination II product or its equivalent to encourage maximizing use of the BPA product. 

ACP Recipient Funds from the ACP will go to an NGO with an account specifically targeted at 

renewable energy development within or serving COU territory, with a preference 

for those pJqi ects serving the affected entity that paid the A CP. 

6 
UM __ - PGE 2012 RPS Complicance Report 

Attachment E 

Page 21 

DRAFT -Do Not Quote or Cite-- DRAFT September 12, 2006 DRAFT 

Enforcement Mechanisms 

Key Point 

Because the IOUs and COUs have different cost cap schemes, the penalty schemes are 

different as well (with the COUs using an ACP scheme instead of penalties). 

Non-adequacy If a progress report is deemed non-adequate the reporting body can request that 

Determination another progress report be submitted within 90 days, and this process can 

continue, until a progress report that is deemed adequate is submitted. 

Penalties for the Any shortfall in a compliance year as determined by the OPUC shall result in a 

IOUs non-recoverable penalty of at least (intentionally left blank in the proposed 

legislation ) amount per MWh of shortfall. An ACP would not necessarily require 

aJ.Jenalty amount, although other penalties may be imposed. 

Penalty Recipient Penalties will be paid to the NGO sub-contracted to the OPUC to manage public 

pu:rpose charge funds for the public good 

Penalties for the Penalties are not necessary for the CO Us because of the use of the ACP 

CO Us mechanism. If a COU refuses to pay the ACP the AG should be able to act. 

Interactions with other Policies 

Future Carbon Double counting of the greenhouse gas emission attributes for any future 

Regulatory greenhouse gas cap is not allowed (i.e., retiring a REC in the two different 

Policies systems). Double use of a REC (retiring the REC in one system only, but 

allowing for compliance to be met in another system) for other accounting systems 

may be allowed contingent on the provisions of future regulatory policies. 

State PURPA Modify Public Purpose Charge Statute ORS 757.612 (4) to require PGE and 

Pacific Power to meet state PURPA Statute ORS 758.505 to 758.555. 

Changes to the RPS 

Key Point 

In order to create a long-term viable market for renewable energy in Oregon some degree 

of regulatory certainty is needed. Thus, putting in place mechanisms to change the RPS 

policy is not ideal. On the other hand, there will undoubtedly be a need to integrate 

technical fixes to the policy over time to accommodate unexpected consequences. 

Periodic Task 

Force 

A task force will convene periodically to evaluate the progress of the RPS and 

report back to the Legislature if there are items that need to be addressed through 

legislation to ensure the continued success of the RPS. The task force should be 

able to recommend accelerating goals if necessary, but not decreasingthe goals. 

7 
UM __ - PGE 2012 RPS Complicance Report 

Attachment E 

Page22 

October 5, 2006 version- annotated 11/6/2006 

Oregon RPS and Related Policy Legislative Package Outline 

Relating Clause 

Relating Clause "Relating to Renewable Energy" 

Fundamental Architecture 

Basis of l Compliance with the renewable portfolio standard (RPS) will be measured in energy 

Compliance units of total sales to retail customers in Megawatt-hours (MWh) 

Compliance I Renewable Energy Certificates (RECs) in units of one (1) Megawatt-hour ( MWh) 

Mechanism from the Western Renewable Energy Generation Information System (WREGIS) 

Structure J One tier with new and some existing facilities eligible, but with primary and 

secondary RPS requirements dell_ending on percentage ofload served. 

Finn FBS Power I No COU shall be req~ed to lose its rights to firm Federal Based System power 

through the RPS. Th1s guarantee does not extend to non-firm power. 

Primary Renewable Portfolio Standard (RPS) for Utilities 

PrimaryRPS All utilities that are responsible for one (1) percent or greater of total retail electric 

Applicability sales in the State of Oregon (as measured by percent of MWh sales) are subject to 

Threshold the Primary RPS requirements as follows: 

End Target 25 percent of retail load by 2025 and each year thereafter 

Interim Targets 5 percent of retail load by_ 2011 and each year thereafter until20 15 

15 percent of retail load by 2015 and each year thereafter until2020 

· 20 percent of retail load by 2020 and each year thereafter unti12025 

Secondary Renewable Portfolio Standard (RPS) for Utilities 

Secondary RPS All utilities in Oregon that do not fall under the Primary RPS must meet the 

Policy Threshold requirements. of a Secondary RPS as follows: 

End Target 60 percent of retail load growth by 2025 and each year thereafter 

Interim Targets 20 percent of retail load growth by 2015 and each year thereafter until 2020 

40 percent of retail load growth by 2020 and each year thereafter until2025 

Load Growth Load growth for affected entities will be measured as the difference in retail load 

Computation between two five-year averages, one for the base year and one for the compliance 

year, with each normalized for weather conditions. The five-year average for the 

comp Hance year will consist of the compliance year and the four preceding years. 

The base year average will consist of the five-year average of2002 through 2006. If 

the difference in retail load yields no or negative load growth, then load growth for 

that period will be considered to be zero for the purposes of the RPS. 
UM - PGE 2012 RPS Complicance Report 

October 5, 2006 version- annotated 11/6/2006 

Primary RPS Opt- Any utility may opt in to the Primary RPS if they so choose, but must stay with the 

in Primary RPS for a minimum of five years once they have opted for the standard, 

regardless of whether they remain or fall below the threshold. 

"Drift" into Any entity that grows such that it falls or "drifts" into the Primary RPS after the RPS 

Primary Standard enactment date must meet the Primary RPS on the same time line as if they had been 

under the standard at the enactment date of the RPS. 

Renewable Portfolio Standard for Electricity Service Suppliers (ESSs) 

ESS RPS The RPS requirement for ESSs serving Oregon load consists of an amount of load 

Obligation equal to the aggregate total of obligations that would exist as if each customer 

served by the ESS were instead being served by its applicable utility based on the 

service territory in which the customer or service location is situated. 

locc D 

Qualifying Renewable Resources 

Electricity Wind 

Derived From: Solar photovoltaic and solar thermal generation 

Wave, tidal, and ocean thermal 

Geothermal 

Biogas from organic sources, wastewater, anaerobic digesters, or landfills. 

Biomass, and byproducts from that biomass, based on (I) organic human or animal 

waste; or (2) solid organic fuels from wood, forest, or field residues; or (3) dedicated 

energy crops. Spent pulping liquor is considered an eligible byproduct for purposes 

of compliance with this RPS. None of the above products may include (!)wood 

pieces that have been treated with chemical preservatives such as creosote, 

pentachlorophenol, or ccp_per-chrome-arsenic or (2) municipal solid waste. 

Attachment E 

Page 23 . 

C~mment [BDl]i : 

'Remo~ed by general:: · · agreerileritat bst . · · ·.·.·. ·· 

meeting .. · ../.·.··.· ··••·· 

Incremental outputofnon-h;ydro generation units using qualif)dng renewable 

sources that have ~~iri(jilstfublYPPE~e~~e_9. %g~~t!~~ 11_SjJ!&. ~~bj~ !:eP.~'!Y!!~l~ ______ - Comment [BD2]: 

resources through capital investments made after the enactment ofthis RPS. Removed as requested. 

Hydroelectric facilities located outside protected areas as defined by federal law in 

effect on the enactment date of SB 1149. 

The increment of improvement resulting from efficiency upgrades to an existing 

hydropower facility. Efficiency upgrade projects on BP A facilities qualifY, but only 

the amount proportional to Oregon's allotted share (as measured by the aggregated 

load of Oregon's consumer-owned utility BPA customers) of the FBS for the 

COI11Pliance_year maybe utilized by affected entities for compliance with the RPS. 

The incremental renewable energy proportion of a multi-fuel generation process. 

Hydrogen that is reformed from or electrolyzed entirely from the qua!if)dng 

renewable resources listed above. 

Additional The determination as to whether additional qualifYing resources should be made 

Qualifying eligible for the RPS is left to the periodic task force convened by the Governor (see 

Resources end of outline). Under no circumstances can electricity derived from fossil fuel 

resources, nuclear, or the combustion of municipal solid waste qualify for the RPS. 

2 
Date ofEligibility 

BundledREC 

Geographic 

Eligibility 

Unbundled REC 

Geographic 

Eligibility 

Shaping and 

Firming Resources 

BPA EPP or 

Substantially 

Similar Product 

UM --- PGE 2012 RPS Complicance Report 

Attachment E 

Page24 

October 5, 2006 version- annotated 11/6/2006 

Subject to the geographic constraints noted below, eligible facilities are those using 

qualifying renewable resources thati\Y¢r~_9]2eratj<?_n_al on or af!.e! Jl!nJl!ll)')_,J995. -----

A bundled REC shall be considered to be created at the point when the, (1) 

electricity generated from a facility physically located within the WECC NERC 

region using a qualifying renewable resource is delivered to any affected entity's 

transmission system, the transmission system of the Bonneville Power 

Administration, or the transmission system of any member of the Northwest Power 

Pool kWI.fr~·MfulJ:~~~~i~i:t:! £<?.IItl?.ip.~tioy_~i~ (22 !~e)~~Q~ ~-e9i.fJE~l)y_ ~s~<?_cj~t~c!_ ___ -- with that generation. To be used for compliance with the RPS the powe~ bundled 

with the REC must be procured ~:ii\ii¥.'$~':filii1ii~lt~iltQ.f~\iiiii§peci,fi$9oli$o~1>Y _ 

Comment [BD3]: 

Read. as·''becamen 

c:c>miriE!Ilt tso4J: 

cii~c~m abo:itt using 

:;:~~~Ji; ' .•. the affected entity for transmission to a designated point of delivery identified by the ' 

affected entity or their scheduling agent. However, the electrical power component '--I comment [sos]: 

Misuse of tenninology 

on my part. of that bundled REC may l:J~ ~1lbstitut~d. forpy any combination of equivalent 

system Or other power ~R a reai tiihe qt de~~yed basis ~~~e~Jli.J.!.C~}!t_iq_n_ qfj:];!~ _____ _ 

bundled REC based on the above definition and ultimate delivery of the power with - Comment [BD6]: 

its associated REC to its final destination for distribution by the affected entity. Concern about using 

"Teal.thne,~­

temnnology 

RECs that have been unbundled from their associated electricity must derive from 

facilities that are physically ~~~~t¥.cl V!'.i!~ !h~ ]_a9i.fu: ]io_rt_!J._!V_e~t__a~ _d~fill~d-by_ t_!l~ ____ - comment [BD7J: 

:.dov's Office and staff 

ciliisiderlng WECC 

:v.;ci~J:>~citibNW' .. is~11e (ai\d proposed . 

so/5o G;imprtn:Oise) .. •·•·· 

Pacific Northwest Electric Power Planning and Conservation Act, or those parts of 

California and Nevada that fall within the service territory of affected entities. 

Procurement of bundled RECs as part of a combined renewable and non-renewable 

contractual energy products (e. g., "shaped" or "firmed" power products) is 

permissible but only the proportion of resources in that combination of contracted 

energy resources that are qualifying renewable resources- as determined upon 

inception of the bundled REC -- will count toward compliance with the RPS. 

~lir~N~~~~~~il~~1~r~!i!~w~t~r~~~\V~1r~~~~~w~~:~;cf 

&&~~ Lopg_a~ fit !:112 pQ!ffiSJ~ SJ~ ~~ _!'~SSJ01.'!:.6_!l:P.9~1i.9 _of~l!oP..:PXQc!u_e!s_ 11_!·~ gE!~e~-~d from fussil fuels, nuclear energy, er the eembustion of HHmieipal solid •.vaste aad (ii) 

at least 90 percent ofthe power assoeiated with that IJroduct, based on the 

· composire yearly average portfelio of the BP:A, EPP package offered to a!! ofBPA's 

customers, oaa be attributed to generation from qualifying reE:e\vable resourees 

identified in this RP£ policy. If for any reasoll: the BPA EPP product or 

substantially similar pro duet fails to meet these ariteria an affeoted sntity or its 

representath•e membership asseeiatioll: may, at its or its membership's diseretion, 

IJetition the Oregon Departmeat of Energy to request an exemption for the · •t. .1 .• n. .un Tinn .,.., · · 

_-- Comment [BOB]: 

·Agreed that OregonqualiiDngaP},.RECs 

·wo~Jd be eiigible. The 

·· iestiS sliperfll19iiii .• •.· . • 

Voluntary Renewable Energy Tariff Programs 

Mandatory 

Program 

Use of Voluntary 

Green Energy 

Purchases in RPS 

All utilities will be required to offer a voluntary green power purchasing program to 

their customers. Beyond some basic parameters (similar to Washington statute), 

program implementation details are at the discretion of the utility. 

~SS.:~}l(l!§rfe1f§*~?I~· ~~#iY,P.r.4Ptir~49Y:~ff'~<~teq ?.#~~~s a)lqus~qto s~~isfy , , , ~~~s~:!e[~~;l: 

voltintro' CUStomer greeD.priciJigfariffprogr~r):J.S ?r:eiiqteligiblefor COmpliance F 1 ideaof''rtiturning" 

withtheRP.S:I_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ RECs from state 

facilities to affected 

entities for RPS use. 

3 
UM - PGE 2012 RPS Complicance Report 

Attachment E 

Page25 

October 5, 2006 version- annotated 11/6/2006 

Firm FBS Power Full or Partial Exemption 

Applicability All consumer-owned utilities that receive a preference allocation of Federal Base 

System (FBS) power from the Bonneville Power Administration (BPA). 

Firm FBS Power No consumer-owned utility shall be required to lose its guaranteed preference power 

Exemption allocation of firm Federal Base System (FBS) power. This guarantee does not 

extend to non-firm power. 

RPS Calculation The total load of an affected entity determines the required portion of!oad that must 

Modifications satisfY RPS resource requirements for a given year. That RPS obligation may be 

reduced, however, if any part of that load portion would unavoidably displace firm 

FBS power preferentially allocated to the affected entity. This partial (or full in 

some cases) exemption from the RPS requirement is limited to an amount equal to 

the amount of firm FBS power that would have unavoidably been displaced if the 

full requirements of the RPS were to be applied to the affected entity. 

Mid-Columbia Hydropower Obligation Deferment 

Applicability Consumer-owned utilities with historic low-cost power contracts for Mid-Columbia 

power from Mid-Columbia dams owned by Washington public utility districts. 

Obligation After accounting for any displacement of firm FBS power, any consumer-owned 

Deferment utility that would face a further displacement of power derived from an active 

historical low-cost, long-term power contract with a Mid-Columbia hydropower 

facility may, for that compliance year, reduce their RPS obligation by the equivalent 

amount of the power delivered that year through that historical low-cost long-term 

power contract. When the historical low-cost, long-tenn contract expires the 

consumer-owned utility is not allowed to defer this part of their obligation any longer 

and must procure the appropriate resources to meet this portion of their RPS 

obligation. However, if the historical low-cost, long-term contract is renewed-- with 

an increase in cost that does not exceed a 10 percent increase on inflation-adjusted 

terms -- than the deferment ofthis portion of the affected entity's obligation may 

continue through the next contract period. 

Renewable Energy Certificates 

Verification 

Long-term 

Contracting 

Standard 

Unbundled REC 

Upper Limit for 

Primary Standard 

RECs used for compliance must be certified by the WREGIS or its successor 

organization, or if necessary, another tracking mechanism designated jointly through 

consensus by the Oregon PUC and the Oregon Department of Energy. 

lr ' ' '· .,).,".· "-······ .. D :4~ +1- .. 

...... '.t; ...... · ..... ·'' ...... , · .... · ... ·.· ....... ,.:'(, .. ,,·;,,,·· .. . ,71.',J.:.: .. ··:· .. ·~· .. · . ".J ~~ ~ 

req~irO!fi~S,~S(~oq~ atJeest}5 percent efllie~eFfoCs \lnder loag teim 

SQ!ltiacis of atliias(io )'ear~ iB d'!iiac:t'imt. The;e is nel'centraet$g stas:dard fer the "··"·'·'':.' ;,;··.··;·riri0~':',:, .. :.., .. , ... ,,: iii .... ':·''...:·· ..... '.:···:;.·.,, ... , ... ·.::'· :t.., .... .., ..... ,···n'ill'10. · .···::.. '· ..... · ·. ·.: ... : ~" , D<'<'. ·I 

' 

No more than 20 percent (or a higher limit as determined by PURPA QF purchases) 

of an affected entity's annual compliance for the Primary RPS can be met through 

the use ofunbtmdled RECs. Unbundled RECs from qualifYing customer-sited or offgrid facilities are exempt from this upper limit. 

4 

- Comment [BDlOJ: 

Contracting standard 

to be dropped, May .need some authority 

for PUC to step in if ic 

probiemdo\VJ1. th~linei 
Unbundled REC 

Upper Limit for 

Secondary 

Standard 

RECs from 

PURPAQF's 

.. 

RECsftom 

Owned Facilities 

RECs from Public 

Purpose Charge 

Funded Projects 

Allocation of 

RECs for MultiState IOUs 

. -' 

-. 

Multi-State RPS 

REC Compliance 

No Disaggregation 

ofRECs 

Off-grid and 

Customer-sited 

Resources 

UM __ - PGE 2012 RPS Complicance Report 

Attachment E 

Page26 

October 5, 2006 version- annotated 11/6/2006 

No more than 60 percent (or a higher limit as determined by PURPA QF purchases) 

of an affected entity's annual compliance for the Secondary RPS can be met through 

the use of unbundled RECs. Unbundled RECs from qualifying customer-sited or offgrid facilities are exempt from this upper limit. 

' 

If an affected entity purchases a bundled REC from a PURP A "Qualifying Facility" 

(QF) that delivers power on a real-time basis to Oregon than the computed upper 

limit for that compliance year on unbundled RECs for that affected entity is raised 

by oneREC's worth of power (1 MWh), with the upper limit on unbundledRECs 

increasing cumulatively for each bundled REC purchased from a PURP A QF . 

Affected entities may satisfy the requirements of the RPS with generation owned by 

the affected entity to the extent that the RECs generated from that power are kept 

and retired by the affected entity (and the RECs must be WREGIS certified). 

~ene.ya9~e·•·~~~rgyyr~qit,s(:@Q§).§~(llf~A9g;u¥'.e4.fi9tlifii6jeP.tsfti~<l~Pi•the 

ptiblic_.ptirpo~~·c)J;lrge,aridietiredq~ l)ehalfofiatep~y~rs.•shall.l)e fredited t(l the 

affected entity. ia ·l.$es~ ~eA~~e·t~tsi:Y ilie pfe,fe~t 8i J3j,¥i_j eetil ifi:e ~seats a.!_ _______ 

For a multi-state investor-owned utility, the share ofbundled_RECs (associated with 

an owned project or a power purchase) allocated to Oregon should, at a minimum, 

include all RECs associated with the above-market costs paid by Oregon ratepayers 

for the power or project and a fair allocation of RECs for market cost purchases (or 

cheape~) as determined through the OPUC and its proceedings. · 

RECs retired for compliance with the Oregon RPS must be counted toward the 

Oregon RPS and can not be used for compliance with any other state's RPS. 

RECs used for compliance with the RPS must include all environmental attributes 

associated with that REC from its inception. No environmental, emissions, or other 

attribute of the REC may be removed and traded, sold, or otherwise retired for use 

with any other compliance system or attribute financial market. 

RECs from customer-sited and off-grid qualifying renewable resources located 

within Oregon are eligible for compliance as long as t)ley meet the verification 

procedures and submittal processes set forth by the WREGIS operational roles, 

Comment [BOll}: 

Oops. Obviously 

meant those who buy 

Jb~ project's power. 

Resource Diversity 

Set-asides or There are no specific percentage procurement requirements for specific resources or 

"Carve Outs" resource types within the RPS, premised on substantive changes to the PPC. 

Renewable Energy Focus the renewable energy portion of the Public Purpose Charge (PPC) on funding 

Component of the a mix of projects of20 MtN or less and exclude funding of projects larger than 20 

Public Purpose MtN. Require as part of this statute that the OPUC will ensure that implementation 

Charge of public purpose charge programs reflects this change in focus. 

Community-Level Community-based renewable energy projects are an essential element of Oregon's 

Renewable Energy energy policy, and it is a goal of the State of Oregon that at least 8 percent of 

Goal Oregon's electrical retail load comes from a mix of small-scale renewable energy 

projects of by 2025. To the extent feasible, all state agencies should modify or 

establish relevant policies and procedures to help the state achieve this _goal. 

5 
UM - PGE 2012 RPS Complicance Report 

October 5, 2006 version- annotated 11/6/2006 

Attachment E 

Page 27 

Compliance Procedures 

Compliance Path Retirement ofWREGIS certified RECs by request of affected enti*s 

Compliance Year Every calendar year from the effective date of the RPS onwards will be considered a 

for Pr~mary and compliance year for the Primary standard for which RECs must be retired at the 

ESS Standard request of the affected entity in order to, depending on the year in question, either 

meet a specified target or to maintain a minimum level of compliance with the RPS. 

Compliance Year Every calendar year from the first interim target onwards will be considered a 

for Secondary compliance year for the Secondary standard for which RECs must be retired at the 

Standard request ofthe affected entity in order to maintain a minimum level of compliance 

with the RPS as determined by the load growth methodology and applicable targets. 

Compliance with Each interim target represents a plateau for which each affected entity must satisf'y 

"Hard" Targets for the RPS by retiring, at a minimum, the appropriate number of RECs to meet the 

Primary Standard target for the first year the interim target takes effect and to continue meeting this 

target each year thereafter until the next interim target takes effect. This process 

continues until the end target is reached, at which point affected entities must 

continue to retire at least enough RECs to meet the end target in both the year the 

end target takes effect and each year thereafter ad infinitum. 

Compliance with Each affected entity must submit a compliance plan every two years (or on a 

"Soft" Targets for schedule with lRP filings) to the appropriate reporting body providing specific 

Primary Standard plans to meet the requirements of the RPS, with specific annual renewable energy 

targets set by the affected entity for each year between and before the interim 

targets. For years between interim targets, and between the last interim target and 

the end target, these targets must be designated at a level above the minimum level 

set by the prior interim target. The PUC may establish appropriate procedures for 

investor-owned utilities to align this reporting process to the lRP process to the 

greatest degree possible so as to minimize the administrative burden created by this 

reporting process. 

Compliance with Each affected entity must procure enough RECs to meet or exceed the proportion of 

Secondary load as determined by applying the load growth determination methodology and the 

Standard interim target that is in effect for that compliance year. Failure to procure a 

sufficient quantity ofRECs to meet the RPS will result in penalties being applied. 

Compliance with Each affected entity must procure enough RECs to meet or exceed the proportion of 

ESS Standard load as determined by the ESS load obligation methodology. Failure to procure a 

sufficient quantity ofRECs to meet the RPS will result in penalties being applied. 

Annual Each affected entity shall, within 4 months of the end of each compliance year, 

Compliance submit a letter to the appropriate reporting body reporting the quantity ofRECs 

Update Letter retired that year for purposes of compliance with the RPS. If the affected entity 

failed to meet the designated target or otherwise applicable load quantity for that 

year an explanation for that failure must be provided in the body of the letter. 

Time of A compliance determination with the RPS for each affected entity will be made by 

Compliance the appropriate reporting body 1 to 3 month after submittal of the annual compliance 

Determination letter. For compliance determinations involving interim targets and the end target 

in the Primary standard, the compliance determination will be made between 18 and 

21 months after the compliance year in question to allow for the use ofthe rolling 

average computation methodology in the penalty determination phase. 

6 
Rolling Average 

Penalty Test for 

"Hard" Targets in 

Primary Standard 

Annual Minimum 

Compliance 

Determination for 

Primary Standard 

Reporting Bodies 

UM __ - PGE 2012 RPS Complicance Report 

Attachment E 

Page28 

October 5, 2006 version- annotated 11/6/2006 

For the purposes of determining penalties in the Primary standard, an additional 

compliance test with the RPS targets will be applied for the first year of each interim 

target, as well as the end target year and each year thereafter. Compliance for these 

years will be determined by using a rolling average. Compliance with the RPS for a 

given camp Hance year in this situation will be figured by taking the total of the year 

before the compliance year, the total of the year after the compliance year, and the 

total of the compliance year. Those three years are then averaged for a one-year 

average to determine compliance in terms of penalty application for those years in 

which an interim or end target begins. In cases where insufficient RECs have been 

procured to meet the interim or end targets as computed penalties will be applied. 

For years between interim targets in the Primary standard, and between the last 

interim target and the end target, the annual compliance update letter submitted by 

each affected entity will be checked to ensure that at least enough RECs were retired 

that year to surpass the minimum floor established by the prior interim target. If not 

enough RECs were retired by the affected entity to, at a minimum, surpass the 

minimum floor for that year penalties will be assessed accordingly. 

For investor-owned utilities and ESSs: Oregon Public Utility Commission 

For consumer-owned utilities: Oregon Department of Energy 

Flexibility Mechanisms 

Grace or "Truing RECs for a compliance year may be purchased and retired up to 90 days after the 

Up" Period end of the compliance year for which the RECs are intended to satisfy. 

BundledREC Bundled RECs procured from parties other than the affected entity can be held and 

Banking from used by the affected entity for a period of time equal to Y. of the contract period by 

Market Purchases which the RECs are procured. (e.g., a 10-year contract would equalS years) 

Banking ofRECs Bundled RECs generated by facilities owned by an affected entity and retired by the 

from Owned same affected entity for the sake ofRPS compliance may be held and used for a 

Sources period of up to 10 years. 

RECsfrom Unbundled RECs may not be held (banked) and used in future compliance periods. 

Unbundled RECs They must be purchased and used within either the compliance period or the grace 

period provided for in this policY. 

Borrowing No borrowing from future generation is allowed. Only banked RECs can be added 

to the mix computation in lieu of actually procuring RECs for a given year. 

Cost Recovery 

Recovery All prudently incurred costs associated with RPS compliance are recoverable, 

Standard (for including those associated with transmission and delivery of renewable energy to 

IOUs) customers in Oregon. In addition, compliance with the RPS up to the cost cap limit 

is not considered an above-market cost as defmedin ORS 757.612(1). 

No Disincentive Ensure that activities related to market transformation activities for early-stage 

for Early-Stage renewable energy development (e.g., permitting regarding wave energy) are not 

Market Activity discouraged or penalized by the RPS or cost recovery aspects of related policy. 

7 
UM - PGE 2012 RPS Complicance Report 

October 5, 2006 version- annotated 1116/2006 

Cost Cap Off-ramp Provision 

Cost Cap There will be a cost cap as an integral part of the RPS, and that cost cap will have as 

Mechanism its basis the electric-only portion of an affected entities total revenue requirement. 

Cost Cap The cost cap will be computed using an above market cost test at the time of the 

Procedures resource decision, with the test applied to the total delivered cost of the resource 

using a fair basis of comparison incorporating current 1RP procedures and 

methodologies .. (More details involved with the cost cap are still pending.) 

Cost Cap Limit Currently left blank. 

Enforcement Mechanisms 

Penalties Any shortfall in a compliance year as determined by the OPUC or ODOE shall 

result in a non-recoverable penalty of at least $45 per MWh of shortfall. 

Penalty Recipient Penalties from IOUs will be paid to the NGO sub-contracted to the OPUC to 

manage public purpose charge funds for the public good. Penalties from CO Us will 

be paid to a similar entity (to be determined through rulemaking by the ODOE) for 

renewable energy projects in consumer-owned utility territory or territories. 

Interactions with other Policies 

Future Carbon Double counting of the greenhouse gas emission attributes from a REC for any 

Regulatory future greenhouse gas cap is not allowed (i.e., retiring a REC in two or more 

Policies different systems). Double use of a REC (retiring the REC in one system only; but 

allowing for compliance to be met in another system) may be allowed contingent on 

the provisions of future regulatory policies. 

People's Utility Placeholder for a number of changes to existing statute that may be required for 

Districts Legal PUDs to implement some or all portions of the RPS. Placeholder for additional 

Modifications modifications for other types of CO Us that may be necessary as well. 

Public Purpose Extend the public purpose charge (PPC) through 2025 to be consistent with and 

Charge serve as a complement to the RPS policy for smaller, community-level resources. 

StatePURPA ModifY Public Purpose Charge Statute ORS 757.612 (4) to require PGE and Pacific 

Power to meet state PURP A Statute ORS 758.505 to 758.555. 

Changes to the RPS 

Periodic Task 

Force 

A task force will be convened by the Governor 12 to 18 months after each of the 

interim target years to evaluate the progress of the RPS and report back to the 

Legislature if there are items that need to be addressed through legislation (e.g., 

additional qualifYing resources)_ to ensure the continued success of the RPS. 

8 

Attachment E 

Page 29 
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INITIATIVE 937 

I, Sam Reed, Secretary of State of the State of Washington and 

custodian of its seal hereby certify that, according to the records on 

file in my office, the attached copy of Initiative Measure No. 937 to 

the People is a true and correct· copy as it was received by this 

office. 

1 AN ACT Relating to requirements for new energy resources; adding a 

2 new chapter to Title 19 RCW; and prescribing penalties. 

3 BE IT ENACTED BY THE PEOPLE OF THE STATE OF WASHINGTON: 

4 NEW SECTION. Sec. 1. INTENT. This chapter concerns requirements 

5 for new energy resources. This chapter requires large utilities to 

6 obtain fifteen percent of their electricity from new renewable 

7 resources such as solar and wind by.2020 and undertake cost-effective 

8 energy conservation. 

9 NEW SECTION. Sec. 2. DECLARATION OF POLICY. Increasing energy 

10 conservation and the use of appropriately sited renewable energy 

11 facilities builds on'the strong foundation of low-cost renewable 

12 hydroelectric generation in Washington state and will promote energy 

13 independence in the state and·the Pacific Northwest region.· Making the 

14 most of our plentiful local resources will stabilize electricity prices 

15 for Washington residents, provide economic be~efits for Washington 

16 counties and farmers, create high-quality jobs in Washington, provide 

17 opportunities for training apprentice workers in the renewable energy 

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1 field, protect clean air and water, and position Washington state as a 

2 national leader in clean energy technologies. 

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NEW SECTION. Sec. 3. DEFINITIONS. The definitions in this 

section apply throughout. this chapter unless the context clearly· 

requires otherwise. 

(1) "Attorney general" means the Washington state office of the 

attorney general. 

(2) "Auditor" means: (a) The Washington state auditor's office or 

its designee for qualifying utilities under its jurisdiction that are 

not investor-owned utilities; or (b) an independent auditor selected by 

a qualifying utility that is not under the jurisdiction of the state 

auditor and is not an investor-owned utility. 

(3) "Commission" means the Washington state utilities and 

transportation commission. 

(4) "Conservation" means any reduction in electric power 

16 consumption resulting from increases in the efficiency of energy use, . 

17 production, or distribution. 

18 (5) "Cost-effective" has the same meaning as defined in RCW 

19 80.52.030. 

20 (6) "Council" means the Washington state apprenticeship and 

21 training council within the department of labor and industries. 

22 (7) "Customer" means a person or entity that purchases electricity 

23 ·for ultimate consumption and not for resale. 

· 24 (8) "Department" means the department of community, trade, and 

25 economic development or its successor. 

26 (9) "Distributed generation" means an eligible renewable resource 

27 where the ·generation facility or any integrated cluster of such 

28 ·facilities has a generating capacity of not more than five megawatts. 

29 (10) "Eligible renewable resource" means: 

30 (a) Electricity from a.generation facility powered by a renewable 

31 resource oth~r than fresh water that commences operation after March 

32 31, 1999, where: ( i) The facility is located in the Pacific Northwest; 

33 or (ii) the electricity from the facility is delivered into Washington 

34 state on a real-time basis without shaping, storage, or integration 

35 services; or 

36 (b) Incremental electricity produced as a res.ult of efficiency 

37 improvements completed after March 31, 1999, to hydroelectric 

38 generation projects owned by a qualifying utility and located in the 

2 
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1 Pacific Northwest or· to hydroelectric generation in irrigation pipe.s 

2 and canals located in the Pacific Northwest, where the additional 

3 generation in either case does not result in new water diversions or 

4 impoundments. 

5 (11) "Investor owned utility" has the same meaning as defined in 

6 RCW 19.29A.010. 

7 (12) "Load" means the amount of kilowatt-hours of electricity 

8 delivered in the most recently completed year by a qualifying utility 

9 to its Washington retail customers. 

10 ( 13) "Nonpower attributes" means all environmentally related 

11 characteristics, exclusive of energy, capacity reliability, and other 

12 el.ectrical power service attributes, that are associated with the 

13 generation of electricity f~om ~ renewable resource, including but not 

14 limited to the facility• s fuel type, geographic location,· vintage, 

15 qualification as_an eligible renewable resource, and avoided emissions 

16 of pollutants to the air, soil, or water, and avoided emissions of 

17 carbon dioxide and other greenhouse gases. 

18 (:14) "Pacific Northwest" has the same meaning as defined for the 

19 Bonneville power administration in section 3 of the Pacific Northwest 

20 e.lectric power planning and conservation act (94 Stat. 2698; 16 rr.s.c. 

21 Sec. 839a) . 

22 · (15) "Public facility" has the same meaning as defined in RCW 

23 39.35C.010. 

24 (16) "Qualifying utility" means an electric utility/ as the term 

25 "electric utility" is defined in RCW 19.29A.010 1 that serves more than 

26 twenty-five thousand customers in the state of Washington. The number 

27 of customers served may be based on data reported by a utility in form 

28 861 1 "annual electric utility report," filed with the energy 

29 information administration, United States department of energy. 

30 (17) "Renewable energy credit" means a tradable certificate of 

31 proof of at least one megawatt-hour of an eligible renewable resource 

32 where the generation facility is not powered by fresh water, the 

33 certificate includes all of the nonpower attributes associated with 

34 that one megawatt-hour of electricity/ and the certificate is verified 

35 by a renewable energy credit tracking system selected by the 

36 department. 

37 (18). "Renewable resource" means: (a) Water; (b) wind; (c) solar 

38 energy; (d) geothermal energy; (e) landfill gas; (f) wave, ocean 1 or 

39 tidal power; (g) gas from sewage treatment facilities; (h) biodiesel 

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fuel as defined in RCW 82. 29A.l35 that is not derived from crops raised 

on land cleared from old growth or first-growth forests where the 

clearing occurred after the effective date of this section; and (i) 

biomass energy based on animal waste or solid organic fuels from wood, 

forest, or field residues, or. dedicated energy crops that do not 

include (i) wood pieces that have been treated with chemical 

prese~vatives such as creosote, pentachlorophenol, or copper-chrom~~ 

arsenic; (ii) black liquor byproduct ~rom paper production; (iii) wood 

from old growth forests; or (iv) municipal solid waste. 

(19) "Rule" means rules adopted by an agency or other entity of 

Washington state government to carry out the intent and purposes of 

this chapter. 

(20). "Year" means the twelve-month period commencing January 1st 

and ending December 31st. 

NEW SECTION. Sec. 4. ENERGY CONSERVATION AND RENEWABLE ENERGY 

TARGETS. (1) Each qualifying utility shall pursue all available 

conservation that is cost-effective, reliable, and feasible. 

(a) By January 1, 2010, using methodologies consistent with those 

used by the Pacific Northwest electric power and conservation planning 

council in its most recently· published regional power plan, each 

qualifying utility shall identify its achievable cost-effective 

conservation potential through 2019. At least every two years 

th~reafter, the qualifying utility shall review and update this 

assessment for the subsequent ten-year period. 

(b) Beginning January 2010, each qualifying utility shall establish 

and make publicly available a biennial acquisition target for cost~ 

effective conservation consistent with its identification of -achievable 

opportunities in (a) of this subsection/ and meet that target during 

the subsequent two-year period. At a minimum, each biennial target 

~ust be no lower than the qualifying utility's pro rata share for that 

two-year period of its cost-effective conservation potential for _the 

subsequent ten-year period. 

(c)· In meeting its conservation targets, a qualifying utility may 

count high-efficiency cogeneration owned and used by a retail electric 

customer to meet its own needs. High-efficiency cogeneration is the 

sequential production of electricity and useful thermal energy from a 

common fuel source/ where, under normal operating conditionsr·the 

facility has a useful thermal energy output of no less than thirty4 
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1 three percent of the total energy output. The reduction in load due.· to . 

2 high-efficiency cogeneration shall be: (i) Calculated as the ratio of 

3 the fuel chargeable to power heat rate of the cogeneration facility 

4 compared to the heat rate.on a new and clean basis of a. 

5 best-cormner<;::ially available technology combined-cycle natural gas-fired 

6 combustion turbine; and (ii). count.ed towards meeting the bierlliial 

7 conservation target in the same manner as other conservation savings. 

8 (d) The cormnission may determin~ if a conservation program 

9 implemented by an investor-owned utility is cost-effective based on the 

10 cormnission's policies and practice. 

11 {e) The cormnission may rely on its standard practice for review and 

12 approval of investor-owned utility conservation targets. 

13 (2) (a) Each qualifying utility shall use eligible renewable 

14 resources or acquire equivalent renewable energy credits, or a 

15 combination of both, to meet the following annual targets: 

16 (i) At least three percent of its load by January 1, 2012, and each 

17 year.thereafter through December 31, 2015; 

18 {ii) At least nine percent of its load by January 1, 2016, and each 

19 year thereafter through December 31, ~019; and 

20· (iii) At least fifteen percent of its load ·by January 1, 2020, and 

21 each year thereafter. 

22. (b) A qualifying utility may count distribu-ted generation at double 

23 the facility's electrical output if the utility: (i) Owns or has · 

' 24 contracted for the distributed generation and the associated renewable 

25 .energy credits; or \ii) has contracted to purchase the associated 

26 renewable energy credits. 

27 (c) In meeting the annual targets in (a) of this subsection, a 

28 qualifying utility shall calculate its annual load based on the average 

29 of the utility's load for the previous two years. 

30 (d) A qualifying utility shall be considered in compliance with. :Om 

31 annual target in (a) of this subsection if: (i) The utility's·weather32 adjusted ~oad for the previous three years on average did not increase 

33 over that time period; (ii) after the effective date of this section, 

34 the utility di¢1 not cormnence or renew ownership or incremental 

35 purchases of electricity from resources other than renewable resources 

36 other than on a daily spot price basis and the electricity is not 

37 offset by equivalent renewable_ energy credits; and (iii) the utility 

38 invested at least one percent of its total annual retail revenue 

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1 requirement that year on eligible renewable resources, renewable energy 

2 · credits, or a combination of. both .. 

3 (e) The requirements of this section may be met for any given year 

4 with renewable energy credits produced during that year, the preceding 

5 year, or the subsequent year. Each renewable energy credit may be used 

6 only once to meet the requirements of this section. 

7 (f) ·rn complying with the targets established in (a) of this 

8 subsection, a qualifying utility may_not count: 

9 (i) Eligible renewable resources or distributed generation where 

10 the associated renewable energy credits are owned by a separate entity; 

11 or . 

12 (ii) Eligible renewable resources or ·renewable energy credits 

13 obtained for and used in an optional pricing program such as the 

14 program established in RCW 19.29A.090. 

15 (g) Where fossil and combustible renewable resources are cofired in 

16 one generating unit located in the Pacific Northwest where the cofiring 

17 commenced after March 31, 1999, the unit shall be considered to produce 

18 eligible renewable resources in direct proportion to the percentage of 

19 the total heat value represented by the heat value of the renewable 

·20 resources. 

21 (h) (i) A qualifying utility that acquires an eligible renewable 

22 resource or renewable energy credit may count that acquisition a.t one. 

23 and two-tenths times its base.value: 

24 (A) Where the eligiblerenewable resource comes from a facility 

25 that commenced operation after December 31, 2005; and 

26 (B) Where the. developer of· the facility used apprenticeship 

27 programs approved by the council during facility construction. 

28 (ii) The council shall establish minimum levels of labor hours to 

29 be met through apprenticeship programs to qualify for this extra 

30 credit. 

31 (i) A qualifying utility shall be considered in co~pliance with an 

32 annual target in (a) of this subsection if events beyond the reasonable 

33 control of the utility that could not have been reasonably anticipated 

34 or ameliorated prevented it from meeting the renewable energy target. 

35 Such events include weather-related damage, m~chanical failure, 

36 strikes, lockouts, and actions of a governmental authority that 

37 adversely affect the generation, transmission, or distribution of an 

38 eligible renewable resource under contract to a qualifying utility. 

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1 (3) Utilities that become qualifying utilities after December 31, 

2 2006, shall meet the requirements- in this section on a time frame 

3 comparable· -in length to that provided for qualifying utilities as of 

4 the effective date of this section. 

5 · NEW SECTION. Sec. 5. RESOURCE COSTS. (1) (a) A qualifying utility6 shall be considered in compliance with an annual target created in 

7 section 4(2) of this act for a given year if the utility invested four 

8 percent of its total annual retail revenue requirement on the 

9 incremental costs of eligible renewable resources, the cost of 

10 renewable energy credits, or a combination of both, but a utility may 

11 elect to invest more than this amount. 

12 (b) The· incremental cost of an eligible renewable resource is 

13 calculated as the -difference between the _levelized delivered cost of 

14 the eligible renewable resource, regardless of ownership, compared to 

'15 the leve:I_ized delivered cost of an equivalent amount of reasonably 

16 available substitute resources that do-not qiJ.alify as eligible 

17 renewable resources, where the resources being compared have the same 

18 contract length or facility life. 

19 (2) An investor-owned utility is entitled to recover all prudently 

20 incurred costs associated with compliance with this chapter. The 

21 

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23 

24 

25 

26 

commission shall address cost recovery issues of qualifying utilities 

that are investor-owned utilit·ies tha·t serve both in Washington and in 

other states in complying with this chapter. 

NEW SECTION. Sec. 6. ACCOUNTABILITY AND ENFORCEMENT. (1) Except 

as provided in subsection -(2) of this sect_ion, a qualifying utility 

that fails to comply with the energy conservation or renewable energy 

27 · targets. established in section 4 of this act shall pay an 

28 administrative penalty to the state of Washington in the amount of 

29 fifty dollars for each megawatt-hour of shortfall. Beginning -in 2007, 

30 this penalty shall b~ adjusted annually according to the rate of change 

31 of the inflation indicator, gross domestic product-implicit price 

32 deflator, as published by the bureau of economic analysis of the United 

33 States department of commerce or its successor. 

34 (2) A qualifying utility that does not .meet an annual renewable 

35 energy target established in section 4(2) of this act is exempt from 

36 the administrative penalty in subsection (1) of this section for that 

37 year if the commission for investor-owned utilities or the auditor for 

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1 all other qualifying utilities determines that the utility compli.ed 

2 with section 4(2) (d) or (i) or 5(1) of this act. 

3 (3) A qualifying utility must notify its retail electric customers 

4 in published form within three months of incurring a penalty regarding 

5 the size of the penalty and the reason it was incurred. 

6 (4) The commission shall determine if an investor-owned utility may 

7 recover the cost of this administrative penalty in electric rates, and 

8 may consider providing positive ins:entives for an investor-owned 

9 utility to exceed the targets established in section 4 of this act. 

10 (5) Administrative penalties collected under this chapter shall be 

11 ·deposited into the energy independence act special account which is 

12 hereby created. All receipts from administrative penalties collected 

13 under this chapter must be deposited into the account. Expenditures 

14 from the account may be used only for the purchase of renewable energy 

15 credits or for energy conservation projects at public facilities, local 

16 government facilities, community colleges, or state univ~rsities. The 

17 state shall own and retire any. renewable energy credits purchased using 

18· moneys from the account. Only the director of general administration 

19 or the director's designee may authorize expenditures from the account. 

20 The ac~ount is su:Oj ect to allotment procedures under chapter 43. 88 RCW, 

21 but an appropriation is not required for expenditures. 

22 ( 6) For .a qualifying utility that is an investor-owned utility,, the 

23 commission shall determine compliance with the provisions of this 

24 chapter and assess penalties for noncompliance as provided in 

25 subsection (1) of this section. 

26 (7) For quC11ifying utilities that are not investor-owned utilities, 

27 the auditor is responsible for auditing compliance with this chapter 

28 and rules adopted under this chapter that apply to those utiiities and 

29 the attorney general is responsible for enforcing that compliance. 

30 ·NEW SECTION. Sec. 7 . . REPORTING AND PUBLIC DISCLOSURE. (1) On or 

31 before June 1, 2012, and annually thereafter, each qualifying utility. 

32 shall report to the department on its progress iri the preceding year in 

33 meeting the targets established in section 4 of this act, including 

34 expected electricity savings from the biennial conservation target, 

35 expenditures on conservation, actual electricity savings results, the 

36 utility's annual load for the prior two years, the amount of 

37 megawatt-hours needed to meet the annual renewable energy target, the 

38 amount of megawatt-hours of each type of eligible renewable resource 

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accru.ired, the type and amount of renewable energy credits acquired, and 

the percent of its total annual retail revenue requirement invested in. 

the incremental cost of eligible renewable resources and the cost of 

renewable energy credits. For each year that a qualifying utility 

elects to demonstrate alternative compli;,_nce under section 4 (2) ·(d) or 

(i) or 5(1) of this act, it must include in its annual report relevant 

data to demonstrate that it met the criteria in that section. A 

qualifying utility may submit its !eport to the department in 

conjunction with its annual obligations in chapter 19.29A RCW. 

(2) A qualifying utility that is an investor-owned utility shall 

also report all information required in subsection (1) of this section· 

to the commission, and all other qualifying utilities shall also make 

all information required in subsection ( 1) of this section available to 

the auditor. 

·(3) A qualifying utility shall also make reports required in this 

section available to its customers. 

NEW SECTION. Sec. 8. RULE. MAKING .. (1) The commission may adopt 

rules to. ensure the proper implementation and enforcement of this 

chapter as it applies to investor-owned utilities.· 

( 2) The department shall adopt rules concerning only process, 

timelines, and documentation to ensure the proper implementation of 

this chapter as it applies to qualifying utilities that are not 

investor-owned utilities. Those rules include, but are not" limited.to, 

rules associated with a qualifying utility's development of 

conservation targets under section 4(1) of this act; a qualifying 

utility's decision to pursue alternative compliance in.section 4 (2) (d) 

or (i) or 5(1) of this act; and the format and content of reports 

required in section 7 of this act. Nothing in this subsection may be 

construed to restrict the rate-making authority of the commission or a 

qualifying utility as otherwise provided by law. 

(3) The commission and-department may coordinate in developing 

rules related to process, timelines, and documentation that are 

necessary for implementation of this chapter. 

(4) Pursuant to the administrative procedure act, chapter 34.05 

RCW, rules needed for the implementation of this chapter must be 

adopted by December 31, 2007. These rules may be revised as needed to 

carry out the intent and purposes of this chapter. 

9 
1 NEW SECTION. Sec. 9. 

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CONSTRUCTION. The provisions of this 

2 chapter are to be liberally construed to effectuate the intent, 

3 policies/ and purposes of this chapter. 

4 NEW SECTION. Sec. 10. SEVERABILITY. If any provision of this act 

5 or its application to any person or circumstance is held invalid 1 the 

6 remainder.of the act or the application of the provision to other 

7 persons or circumstances is not affected. 

8 NEW SECTION. Sec. 11. SHORT TITLE~ This chapter may be known and 

9 cited as the energy independence act. 

10 NEW SECTION. Sec.. 12. CAPTIONS NOT LAW. Captions used in this 

11 chapter are not any part of the law. 

12 NEW SECTION. Sec. 13. Sections 1'through 12 of this act 

13 constitute a new chapter in Title 19 RCW. 

--- END ---

... 

10 
UM __ - PGE 2012 RPS Complicance Report 

Attachment-E 

RPS 2010 Advisory Committee Meeting 

Meeting #3 Minutes 

1:00pm to 3:30pm 

Oregon Department of Energy 

Members Present: 

Jeff Bissonnette, CUB 

Ellie Booth, Covanta Energy 

Lisa Brown, WaterWatch of Oregon 

(alternate) 

Megan Decker, RNP 

Ryan Flynn, PacifiCorp 

Gary Marcus, Falls Creek Hydro 

Members Absent: 

Line Cannon, Forest Resources and Taxation 

!(ate Miller, Trout Unlimited 

Glenn Montgomery, OSEIA 

ODOE Staff Present: 

Kip Pheil (Senior Policy Analyst) 

Hillary Dobson (Policy Analyst) 

Other Stakeholders Present: 

Sandra Bishop, Community Energy Systems 

Kim Eshleman, PGE 

Eric Hiaasen, EWEB 

Sandy Flicker, ORECA 

1. Introductions and Agenda Overview 

Brendan McCarthy, PGE 

Tom O'Connor, OMEUA 

Rick Oliver, Central Lincoln PUD/OPUDA 

Doris Penwell, AOC, CREA 

Zaybn Towner, PNGC . 

Sandra Walden, OSEIA (alternate) 

Paul Woodin, CREA 

Andrea Jackson, PGE 

Damon McCauley, PGE 

Karen Reed, Bateman Seidel 

Kyle Roadman, Emerald PUD 

a. Call to order: Kip Pheil called the third meeting of the RPS rulemaking advisory 

.committee to order at 1:05 pm. The meeting was held at the Oregon Department of 

Energy (ODOE). 

b. The committee discussed the meeting minutes from the August 101

h meeting. The 

minutes were approved, but will be amended to include a clarification made by Rick 

Oliver about exemptions for conduits. 

c. The committee previewed the meeting agenda. Ryan Flynn asked if the bundled REC 

discussion would include thee-tag issue. Kip Pheil said that the group probably would 

not get that far during this meeting. 

2. The committee discussed the temporary rules for low Impact Hydro Certification 

-------.,a.-ro"rrD..,.,O"tlE--tiled, and the temporary rules became effective, on August 31st. rhe rules were 

based upon the discussion on low impact hydropower certification from the August 101

h 

meeting. The committee reviewed the substantive rule language. Kip Pheil pointed out 

that the temporary rules use the word "the" instead of {(a" when identifying UHI as the 

national certifiCation agency. He explained that this was done in order to reduce any 

1 

Page 40 
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RPS 2010 Advisory Committee Meeting 

Meeting #3 Minutes 

1:00pm to 3:30pm 

Oregon Department of Energy 

future conflicts and to ensure that determining whether to allow any future 

organization to certify for low impact hydropower would be through rulemaking. He 

also reminded the committee that the rule could be altered \t\lith the additional 

permanent rulemaking if necessary. 

3. The committee discussed the impacts of HB 3674 on pre-1995 facilities. 

a. Kip Pheil reminded the group that ODOE cannot issue Oregon RPS certification for a HB 

3674 facility before April 2010 without WREGIS producingerroneous REC outputfor 

2010 electricity. Because HB 3674 makes January 2011 electricity from these facilities 

the first eligible for the RPS, no 2010 vintage RECshould show an Oregon RPS 

certification. He also said that Line Cannon, who is key to this discussion, is out of town 

and so it would be best to postpone this item to a future meeting. 

b. Kip Pheil explained that the,rulemaking will clarify protocols for multi-fuel facilities, 

which is a broader than facilities covered by HB 3674. Ellie Booth commented that the 

use of natural gas at Covanta's facility is just for starting up and that the run-time is 

pretty long. She wanted to make sure that those facts are captured. Kip Pheil responded 

that ODOE looks at average hourly feedstock. He described a protocol concept with 

fairly broad parameters, but that is distinct for each facility. 

c. He mentioned that Massachusetts and Illinois have just recently modified their 

procurement practices because of Commerce Clause issues. Providing preferences for 

local facilities may not be possible under a Commerce Clause challenge. 

4. The committee discussed the issue of "stranded generation" {retroactive RECs) 

a. Kip Pheil reviewed the issue. The committee needs to find a mechanism for giving credit 

for qualifying energy that does not have a WREGIS REC. He discussed three options 

including a "straw" proposal 

(http://www;oregon.gov/ENERGY/RENEW/docs/RPS rules mtg3 program9sep2010.pdf) put forth by PacifiCorp, PGE, OMEU and PNGC. 

b. Option 1 is retroactive REC creation through the WREGIS process. This would be the 

cleanest method, but may not necessarily be possible. 

c. Option 2-the straw proposal- is to modify the RPS administrative·rules to provide an 

alternative to WREGIS for the start-up phase. Megan Decker sought to clarify the end 

date of this alternative system. As drafted, the alternative system could indude 

generation from January 2007 to March 2012. The group reviewed the relative statutory 

language. Kip Pheil noted that PUC staff is aware that this is under discussion but, if the 

committee chooses to pursue an alternative to WREGIS, the PUC would need to be 

consulted per the ORS. The straw proposal requires generators to provide metered 

generation data and attestation in an electronic form that is acceptable to the ODOE 

Director. Ryan Flynn noted that 3/31/2012 is the first RPS compliance filing date for 

utilities and the basis for proposing that the alternative system encompass generation 

through that date. He believes that ODOE has the discretion to adopt another system 

·accordingto statute. He answered Jeff Bissonnette's question of whether PacifiCorp 

ever expected to have qualifying energy qutput initially represented with the alternative 

system converted with WREGIS. Ryan Flynn answered that PacifiCorp does plan to use 

WREGIS. Doris Penwell asked a follow-up question of whether the utilities planned to 

2 
UM __ - PGE 2012 RPS Complicance Report 

Attachment E 

RPS 2010 Advisory Committee Meeting 

Meeting .#3 Minutes 

·1:00pm to 3:30pm 

Oregon Depar:tment of Energy 

immediately switch to the WRECJIS system after 3/31/2010. Ryan Flynn said that 

PacifiCorp would. Eric Hiassen commented that EWE~ also has stranded QE from 

beyond the summer of 2007 that they are looking to secure. Megan Walseth-Decker 

asked for added clarification about the 3/31/2012 date, what time period the interim 

system is intended to cover and what time period is for the stranded generation. She 

also asked if the drafters anticipated an end-date for this problem. 

i. Ryan Flynn answered that PacifiCorp's stranded QE was generated in 2007. 

ii. Tom O'Connor answered that his issue is the Bonneville Environmentally 

Page 42 

. Preferred Power (EPP) that was purchased which may include some generation 

from 2008 

iii. Brendan McCarthy explained that the chosen dat~ matches up with the 

··;; statutory first compliance date for utilities and also provides some extra time 

:',,. for issues to be sorted out. PGE has unresolved QE generated through 2009. He 

""· commented thatthe proposed language provides the flexibility to deal with 

·r.; · those issues. 

iv. Kip Pheil said that in order for ODOE to evaluate this proposal, it will need 

better data from the key players, such as when the last qualifying electricity was 

produced that has yet to be.converted to a WREGIS REC. Also, ODOE would 

want to clarify the issue with WREGIS. He noted that there are also independent 

players who may be unaware of this issue. Kip said that the group may want to 

consider an end-date. He noted that at this point, if a facility is not registered 

with WREGIS, there would need to be a convincing reason for why it has not 

been done. Kip said that another interpretation of that c;late is to treat it as the 

last eligible vintage of generation. . 

v. Megan Walseth-Decker asked if that was what the parties who proposed the 

language intended. 

vi. Brendan McCarthy said that for the first half of 2007, PGE sold their RECs with a 

signed attestation, vyhich was sufficient for the voluntary REC-based programs. 

He stated that this proposal is similar and it allows the utility the time necessary 

to work within the WREGIS constraints. He described the proposal as offering 

the maximum amount of flexibility balanced with putting a system in place by 

the end of the year. He confirmed that this alternate system would be confined 

to specifically addressing the backJog issue. He noted that WREGIS does not yet 

accoun~ for output due to hydropower upgrades. 

vii. Kip Pheil noted that there is an identified pilot for how WREGIS will deal with 

the backlog, but WREGIS may not end up going with this. 

viii. Ryan Flynn added that the proposed language uses the term "qualifying 

electricity" for a reason. It is not intended to change what type of electricity 

qualifies, but just to facilitate the WREGIS system. 

ix. E'A'EB <;larified that the intent---e-f-3131/2012 date is to be the date that a facility 

must be registered with WREGIS by. 

d; Doris Penwell asked whether the process for registering a facility with WREGIS requires 

the owner to first register with ODOE. Kip Pheil answered that owners usually contact 

him at the time they have gone through WREGIS not necessarily before. As long as the 

owner has a facility that is using a recognizable renewable energy resource, WREGIS will 

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Attachment E 

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register it. He said that is why choosing 3/31/2012 as the date seems more lenient than 

necessary. Any pre-1995 facility could register with WREGIS right now. Post-1995 

upgrade facilities have to deal with the issue of how to allocate electricity due to the 

upgrade. Kip expects that the end of 2'008 would be long enough. ' 

e. Kip Pheil believes that there are two other major questions with this proposal. First, if 

the proposed system would meet the statutory standards. Second, who would pay for a 

system that would meet those statutory standards, keeping in mind that it could be a 

multi-million dollar system. 

f. Megan Walseth-Decker commented that this language indicates another process but 

does not clarify whether this would be done through rulemaking or administratively. 

Ryan Flynn said the draft anticipates .the system will be established by the Director. Kip 

Pheil asked him wh!=ther he envisioned a stakeholder group being involved. Ryan Flynn 

responded that he had not given that point much thought . 

. g. Doris Penwell asked how the utilities had planned on dealing with this issue prior to 

rulemaking. Brendan McCarthy answered. that this has been a problem for a long time 

and that they were hoping that WREGIS would accommodate them. 

h. Sandra Walden asked about the costs associated for registering with WREGIS and 

commented on the importance of keeping the costs low. Andrea Jackson answered that 

WREGIS registration costs depend on the total generator capacity of each account. She 

believes that that maximum is $1500 per year to maintain an account and that there is 

no charge to register, However, to transfer or retire a REC, WREGIS charges up to one 

cent per REC. Rick Oliver suggested that Sandra Walden check the WREGIS website for 

more information. Kip Pheil added that WREGIS costs are very minimal with the 

exception that for a very small system, the minimum annual cost of about $200 per year 

can be relatively large compared to the REC value. Tom O'Connor said that for him, 

these costs are a big issue and that BPA has established sub-accounts to handle REC 

banking for small utilities but the jury is still out as far as they are concerned for 

compliance activities. 

i. Sandra Walden asked ifthe oufcome ofthis rulemakingwould add to the cost. Kip Pheil 

explained that the proposal is an alternative for some of the output. 

j. Kip Pheil introduced a third option. The company that has built all of the tracking 

systems, including WREGIS, has also developed the North American Renewables 

Registry (NARR). NARR does not have the same kind of constraints that are in WREGIS 

meaning that it may be an alternative with lower costs. Ther·e is an agreement between 

WREGIS and NARR to address duplicate registration and Kip is not certain that WREGIS 

would accept this proposal. NARR could potentially provide compliance reports to be 

filed by a utility alongside WREGIS reports. Kip will look into this more.The group needs 

to look irito the other two options as well and then revisit the discussion. 

i. Brendan McCarthy commented on Kip's summary. He pointed out that the 

statutory language does not refer to a REC tracking system; rather it calls for the 

transfer and use that need to be electronic according to the statute. It does not 

necessarily have to be a system that's tracking each REC. 

ii. Jeff Bissonnette added that the statute requires consultation with the PUC and 

asked if ODOE had made any initial consultations. Kip Pheil replied that he had 

talked with PUC staff but on a broad scale. None of the utilities have talked with 

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Meeting #3 Minutes 

1:00pm to 3:30pm 

Oreg_on Department of Energy 

Page 44 

the PUC staff about this. Kip Pheil told the group that he is hoping to have a PUC 

person at the next meeting. 

4. The group discussed the post-1994 upgrade issues 

a. Kip Pheil introduced -the issues to the group. He listed the efficiency v. capacity 

discrepancy, the definition of "operational", and developing protocols for the 

attribution of generation for multi-fuel facilities. In terms of eligible upgrades, ORS · 

469.020(2) refers to "capacity or efficiency" for non-hydropwer projects and ORS 

469.020(3) refers only to "efficiency" for hydropower. Kip drew a parallel to the multifuel analysis. 

b. The term "operational" is used in ORS 469.020(1). Kip added that this is similar to some 

other RPS programs use of a "repowering" provision. ODOE will draft language on this 

subject for the next meeting. There is an argument that at some point, generation 

w0uld not need to be attributed partially to an upgrade but instead a facility might be 

tr.eated like a new machine. Rick Oliver commented that the term "re-built" also seems 

like that would be extending a facility's life. Kip Pheil responded that there might be an 

argument for treating a facility like a new one. He also said that it may be best to try a 

align with California's RPS program except that there may be times when we.would not 

wantto require the replacement of the prime mover as California does. We should work 

through some of those scenarios. 

c. Jeff Bissonnette commented that if investment is made in a facility that increases 

efficiency, at some point there so much investment and efficiency gained that it is truly 

a new plant. He noted the need to confirm that ODOE has legislative authority to make 

that determination. 

d. Sandra Bishop asked if there were reasons not to use the same standard as California. 

Kip Pheil responded that there are a variety of reasons such as the requirement to 

replace the prime mover. 

e. Ellie Booth commented that the biomass plants that have shut in California were closed 

primarily because offuel costs and reduced payment rates in power purchase 

agreements. 

f. Brendan McCarthy commented that there is always some benefit of looking to see what 

other states have done but Oregon may not want to follow other states' paths in this 

situation. He suggested looking at other Oregon statutes that have the phrase "becomes 

operational" in order to determine its meaning. He specifically mentioned that some of 

the "right to farm" laws use that phrase. In Air Quality statutes, it is defined as "related 

to changing the primary design function". The phrase "extending the life" is challenging 

because it can be difficult to distinguish between an extension and routine 

maintenance. He suggested that the group consider the purposes of the RPS, which are: 

1) spurring economic development/investment 2) increasing renewable energy in 

Oregon and 3) lowering the state's carbon profile He believes that based--On-these 

goals, the rules ~hould try to accommodate investments that would help Oregon move 

forward. He used the Boardman plant as an example of an investment that is going to 

be outside ofthe (/generation box", e.g. land purchases, leases, and new crops. 

i. Kip Pheil added that he thought that the California RPS and similar Green-e 

Energy standard might be used by Oregon but as an option for generators 

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RPS 2010 Advisory Committee Meeting 

Meeting #3 Minutes 

1:00pm to 3:30pm 

Oregon Department of Energy 

pursuing those certifications. He said that California has a very specific list for 

what constitutes a new facility and that he would investigate further prior to the 

next meeting. 

ii. Gary Marcus said that it was his understanding that California's law about 

repowering is to get plants that would not otherwise qualify to qualify for the 

RPS. He reminded the group that once a plant has been depreciated 100%, it is 

very easy to meet the percentage of investment for repowering. 

iii. Megan Walseth-Decker asked whether the California repowering standard was 

in statute or in rule. She believes that would help the group determine whether 

the state was working with a broader statutory mandate. Kip Pheil was unsure 

of the answer. Lisa Brown commented that Oregon has not taken the California 

route with hydropower. 

iv. Doris Penwell said that legislative action may be required. 

v. Breridan McCarthy commented that the date January 1, 1995 was chosen for 

political reasons, not because there was any thought at the time about the 

situation that PGE finds itself in now with Boardman. He hopes that a legislative 

fix will not be necessary. The definition of "operational" becomes very 

important. 

vi. Kip Pheil commented that any analysis of an upgrade needs to make sure that 

there is cause and effect with investment and i~creased generation. 

5. The committee discussed the hydropower "efficiencyv. capacity" attribution issue 

a. Kip Pheil introduced the issue by noting the statututory difference between the terms 11efficiency" and "capacity" when used in reference to hydropower facility upgrades. Kip 

had a recent exchange with BPA staff and others which resulted in a refined framework. 

He proposed three possible efficiency categories: 1) equipment upgrades and 

improvements; 2} facility operation improvements; and 3} flow optimization within 

other river conditions. Brendan McCarthy commented that the language in ORS 

469.020(4) may provide some guidance. 

b. Zabyn Towner added thata good starting point for this discussion may be what BPA 

presented to ODOE a few years ago on what qualified as efficiency. He said that BPA 

engineers have examined this issue and may be able to help. Kip Pheil responded that 

while that information may be helpful, it was primarily about specific upgrades. He 

added that attribution can be difficult and gave the example of a hydropower facility 

designed 50 to 70 years.ago and may no longer operate under the original flow patterns. 

Lisa Brown of Water Watch commented on one of the key pieces for differentiatin·g 

between the two terms -the principal that power is being generated based on the same 

amount of water. Rick Oliver commented that it sounds like an efficiency upgrade is 

power in divided by power out. Group members questioned wh~ther capacity would be 

based on nameplate capacity. Kip Pheil acknowledged that this is something that the 

rules would have to be very clear about. 

c. Jeff Bissonnette commented that many ofthese questions stem from the original bill. 

He asked whether there had previously been rulemaking on these subjects. Kip Pheil 

answered that the only ODOE RPS rulemaking was to establish the REC system. Tom 

O'Connor added that people have· been working on these issues for quite awhile. He 

6 
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Attachment E 

RPS 2010 Advisory Committee Meeting Page 46 

Meeting #3 Minutes 

1:00pm to 3:30pm 

Oregon Department of Energy 

said that the capacity v. efficiency issue has become particularly relevant now because 

BPA is starting to make some of these upgrades. 

d. Kip Pheil said that flow optimization would prove the most difficult ofthe three 

categories if the committee decides to take it on. The coll!m~ttee would have to 

determine what the "same amount of water' actually means. He continued that this is 

potentially burdensome because of the cause and effect issue. Lisa Brown responded 

that there is a defined exclusion for changes that result in environmental degradation. 

Kip Pheil agreed that the group needs to think about where these modifications might 

fall but that it is cleaner to say no credit for increasing flow. He also said that this point 

is something for the group to think about prior to the next meeting. 

e. Rick Oliver commented on ORS 469.020(3) and the phrase "Oregon's share" in relation 

to upgrades to the BPA syster.n. He believes that th~re are a few ways of accomplishing 

this. He has been working on this with Bonneville 1

S Deb Malin. He is not sure if this 

needs to be addressed through rulemaking. 

6. The committee discussed other issues 

a. Ryan Flynn asked about the status of the bundled REC issue. Kip Pheil noted that the 

initial set of RPS rules that ODOE filed relied on use of the WREGIS NERC e-tag process. 

That process allows utilities to show compliance with the bundled REC requirement. The 

problem is that the existing OAR does not explicitly note that when a utility takes energy 

directly into its system, there is no transfer of power between utilities, and no e-tag is 

created: The simple solution to this condition is to rely on the REC certificate line that 

lists the "utility to which the GU is interconnected." If the interconnected utility is the 

same as the utility which retires the REC this is alternate proof of a bundled REC. Kip 

noted that WREGIS is revisiting the e-tag procedure to address a wider range of market 

transactions. Ryan Flynn asked if Kip thought this should be an agenda item for the next 

meeting where the group could review draft language. Kip Pheil agreed with this 

proposal. Eric commented that it would be helpful to have a web demonstration for this 

portion of the meeting to allow remote staff to follow the discussion more easily. 

b. Lisa Brown asked how the public can review applications for the RPS. Kip Pheil answered 

that the WREGIS website will show facilities that have received an Oregon certification 

for the RPS but it does not show applications that are in the review queue. Kip said that 

he intends to post a more detailed summary of what has qualified for the RPS on the 

ODOE website. Lisa responded that there needs to be some transparency about what 

generators are being accepted for RPS especially for pending applications. 

c. Jeff Bissonnette asked, in regard to the proposed interim registration system, what 

percentage ofthe utilities' RECs are "unbundled". Ryan Flynn said that PacifiCorp can 

meet up to 20% of its required amount through unbundled RECs. According to Brendan 

McCarthy, PGE's stranded QE are all bundled REC products. Andrea Jackson and Damon 

McCa11ley said that what PGE has stranded wonld not spill over into next (2012] 

compliance period due to the first-in, first-out rule. Their stranded QE represents the 

bulk of the first [2011) compliance period. 

7. The committee planned the next meeting 

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Attachment E 

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RPS 2010 Advisory Committee Meeting 

Meeting #3 Minutes 

1:00pm to 3:30pm 

Oregon Department of Energy 

The next advisory committee meeting is plan neg for October 1, 2010. It will be a lqnger meeting 

which may be in Portlana and ODOE will look into providing a webinar as well. 

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Attachment E 

RPS 2010 Advisory Committee Meeting Page 48 

Meeting #4 Minutes 

9:00am to 3:30pm 

Oregon Dept. of Transportation, Portland, OR 

Members Present: 

JeffBissonnette, CUB 

Line Cannon, Forest Resources and 

Taxation 

Megan Decker, RNP 

Ryan Flynn, PacifiCorp 

Brendan McCarthy, PGE 

Kate Miller, Trout Unlimited 

Glenn Montgomery, OSEIA 

Tom O'Connor, OMEUA 

· Rick Oliver, Central Lincoln 

PUD/OPUDA. 

Doris Penwell, AOC, CREA 

Zaybn Towner, PNGC 

Paul Woodin, CREA 

Members Absent: 

Ellie Booth, Covanta Energy 

Lisa Brown, Water Watch of Oregon 

(alt.) · 

1. fntroductions and Agenda Overview 

Gary Marcus, Falls Creek Hydro Glenn 

Montgomery, OSEIA 

Sandra Walden, OSEIA (alt.) 

ODOE Staff Present: 

Kip Pheil (Senior Policy Analyst) 

Hillary Dobson (Policy Analyst) 

Other Stakeholders Present: 

Jason Heuser, EWEB 

Juliet Jobpson, PUC 

Teri Ikeda, PacifiCorp 

Betsy Kauffman, Energy Trust of 

Oregon 

Lynn Averbeck, ODOT Solar Highway 

Program 

Christie Sharpe, PacifiCorp . 

Nicole Merendino, SunEdison 

1. The Committee noted ·that the minutes from the September 9th meeting have not 

been posted on the ODOE website; therefore, approval is deferred to a later 

meeting. 

· 2. Kip reviewed the webinar logistics. 

2. The committee discussed Multi-Fuel Allocation 

1. Kip Pheil reviewed the WREGIS data entry process, including the generation, 

REC production, and the protocols for how the Oregon RPS could address multifuel allocation process. 

a. The standard approach. First, the generator owner gets the facility 

registered in WREGIS. Tom O'Connor asked if an applicant would need 

to have a particular state or voluntary program in mind when applying to 

WREGIS. Kip answered that is unlikely that WREGIS would require an 

applicant to prove that its generation would meet the requirements of a 

particular state or program before registering it He clarified thatDDtJ..OuE;:,.._ _____ _ 

does not officially begin processing a facility until it has been registered 

with WREGIS. Once a generator is in WREGIS and has the certifications 

from programs that it wants, then that generation date (MWh/month) is put 

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Page49 

into WREGIS by a third party (either the utility or portiori of the utility 

taking the electricity). 

b. Juliet Johnson asked about if the qualifying reporting entity is responsible 

for reporting the actual number of megawatt hours to WREGIS and· 

whether the qualifying reporting entity (QRE) is also responsible for 

registering the generator with WREGIS. Kip explained that the generator's 

owner is responsible for registering the generator with the WREGIS 

system and that the QREs are more like account holders that the 

generators can sign up with. Teri Ikeda of PacifiCorp confirmed this. Teri 

Ikeda from PacifiCorp responded to the question. 

c. Kip showed a sample REC and highlighted where on the certificate to find 

certain information. Tom O'Connor asked where information about the 

QREs would be listed on the REC. Kip pointed to the line listing the 

reporting entity or organization. 

d. Question of whether a facility with multiple qualifying fuel sources would 

need to have multiple QREs? Kip said that electricity that is generated 

from different sources would need to be accounted for separately- that is 

the heart of the multi-fuels issue. There is generally just one reporting 

meter for a facility. Kip explained that WREGIS allows for generator. 

owners to separate output based on different sources. Output does not have 

to go to the QRE through multiple meters for it to be separated in 

WREGIS. 

e. Kip explained that once ODOE is,sues a certification ID for a generator, it 

is like giving someone a _driver's license. It is the license for an Oregon 

generator to produce RECs through WREGIS. Once ODOE OKs it, the 

generator can produce as many certificates as it wants or is capable of 

Once the certification ID is issued, ODOE does not know how many 

RECs a facility produces -that is proprietary information within the 

WREGIS system. ODOE is expected to test with whether the generator 

meets the rules, uses the right resources, uses the right processes to 

generate electricity. 

f. A generator should be able to earn one REC for every megawatt hour of 

qualifying electricity produced. It should be equitable between generating 

owners. There should be no disadvantage to having a single or multi-fuel 

facility. 

2. Kip spoke about the need to balance the precision of compliance with the need to 

inake a decision about whether a generator would qualify. He described how 

California has a de minimus rule for multi-fuels. . 

a. Doris Penwell asked who keeps track of the utilities' compliance status 

with the RPS and where that information would be located. Kip answered 

that the PUC tracks the information for IOUs. The utilities file 

implementation plans every-other year and file updates to those plans 

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Oregon Dept. of Transportation, Portland, OR 

every year in-between. They must file a compliance report in March 2012 

for the 2012 compliance year. 

i. Juliet Johnson asked if there is someplace in WREGIS that says if 

a REC has been used to comply with the Oregon RPS and is 

therefore retired. Kip responded that information is what is turned 

in with compliance reports. In the WREGIS system, once a 

certificate is retired, it is gone. It will also state the reason the REC 

was retired. 

ii. Megan Decker asked who would file the compliance report. The 

account holder generates its own report. 

3. P-rohibited Sources 

· ~~•·. a. Kip quoted· the statute; which states that ODOE may not approve 

:~,, petroleum, natural gas, coal or nuclear fission as an energy source~ Kip 

also pointed out that wood treated with certain chemical preservatives are 

'· · not eligibly for the RPS under statute. 

b. Tom O'Connor asked whether WREGIS maintains a summary list of what 

sources each states consider eligible sources. Kip answered WREGIS has 

not attempted to provide that kind of market information for participation, 

but it would rely on some other entity. Another source is the LawrenceBerkeley Lab. 

4. Source v. Process 

a. In 2010, new sources were made eligible because oflegislative action. 

These sources include some pre-1995 hydroelectric projects, some pre1995 biomass facilities. Also in 2010, a new process was made eligiblethe combustion of municipal solid waste (MSW). 

b. Combustion of treated wood and nuclear fission are still prohibited 

processes in the Oregon RPS. 

5. Multi-Fuel Examples 

a. Biomass combustion such as hog fuel, or saw dust. These types of 

facilities generally need to have natural gas on hand to keep the facility 

gorng. 

b. Concentrating solar power. There are none of these yet in Oregon. One 

thought is to back up solar power with natural gas. 

c. MSW energy recovery.. There is typically some type of natural gas co-fire. 

There is a lot of petroleum-derived waste in the feedstock. 

d. There are some potential sources that may not clearly be eligible or 

ineligible for the Oregon RPS. 

6. Conversion Efficiency 

a. Simple efficiency calculation is energy out over energy in. 

b. Key factors to efficiency, such as the energy density of the fuel source. 

Also, moisture content- how materials are burned. Also, how the machine 

has been built and how it works is important. 

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c. Need to find a way to effectively capture these variables in order to 

determine a consistent efficiency standard. Kip suggests looking at a fairly 

discreet time period. He generally looks at the hourly values of a facility · 

and sum up the results of that over a month. There may be smaller 

facilities where it might be feasible to simply look at monthly averages. 

7. Multi-Fuel Review 

a. Kip tells the group that ODOE will try to develop draft language and 

release it to the committee before the next meeting. 

b. Question of how proprietary data would be protected with ODOE 

requiring certain data to determine efficiency. There are ways .to address 

confidentially concerns. However, what is needed is some general way 

that ODOE will approach these projects, even though probably every 

project will be unique. 

c. Jeff Bissonnette commented that the multi-fuel discussion for MSW is 

pretty limited, based on the statute. Are you going to consider what is in 

the feedstock of an MSW facility? Kip answered that there needs to be 

some sort of feedstock analysis. While the DEQ has some data, it is very 

limited. The only element of this type of facility that can currently be 

easily quantified is how much natural gas is being burned. 

d. Teri Ikeda asked Kip if he had any thoughts on the analytical element of 

the time period over which this data would be available. The older 

facilities would be able to provide this historical data, but it may not .be 

available for the newer facilities. Kip answered that there is a "goodthrough" date issued with the Oregon certification. This is a way to come 

back to the analysis after the facility has been running and could serve as 

an audit. 

e. Rick Oliver asked about multi-fuel facilities tracking their output, 

particularly about peaking. Kip answered that in terms of tracking the 

generation, the typical approach is to create a spreadsheet that keeps track 

of hourly activity. WREGIS knows what the capacity of a facility is, so 

can tell if the report is more than what is possible. 

f. Tom 0' Connor asked about the analysis of a facility that is somewhere in 

WECC but not in Oregon. The generator operator can give proxy access 

for a generating unit to anybody, so Kip could be allowed to check that the 

generator's output is complying with expectations. WREGIS can forcibly 

retire RECs in the case of fraud - ifthe operator did not 

g. Juliet Johnson asked how California has been handling this situation. She 

suggested having a conservative standard for the amciunt of natural gas 

that is feeding into the system. If an applicant wants to argue that they 

have a super-efficient way of operating, then the burden is on them to 

prove that the standard should not apply to them and that they should have 

a more favorable efficiency. Kip said that her idea tracks a conversation 

that he has had with EWEB. 

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RPS 2010 Advisory Committee. ~eeting 

Meeting #4 Minutes 

9:00am to 3:30pm 

Oregon Dept. of Transportation, Portland, OR 

Page 52 

h. Doris Penwell asked if ODOE regularly goes back and monitors 

generating units. Kip replied that the only multi-fuel facility that has ever 

made it through the certification process soon stopped operating. He 

would like to have proxy access to the data spreadsheets in the future. 

3. The committee discussed the issue of upgrades. 

1. This is possibly relevant even to a facility that is part of the pre-1995 biomass that 

is now eligible. 

2. Commenced operation question 

a. The committee has talked about how this issue compares to the California 

_::.; RPS and the Green-e program. California has an investment threshold and 

·2 a requirement that the prime mover is replaced. If a facility completely 

modifies its fuel source, then also treated as a new facility. 

· ~: b. Could. have a con~ervative standard, such as an investment threshold, or if 

:.. it meets the Green-e requirement, then Oregon would accept it as a new 

facility. 

c. Kip asked the Committee for comments or thoughts on rule language. 

Megan Walseth-Decker stated that she is in fa':'or of keeping this area as 

simple as possible and likes the Green-e standard. She also stated that she 

is wary of how much room the phrase "become operational'' gives the 

group. 

d. Brendan responded saying he believes that ODOE has broad rulemaking 

authority in this area based on policy statements. Believes the question is 

whether the phrase "becomes operational" is an inexact term or a 

delicative term, and whether that distinction matters. 

3. General protocols for dealing with upgrades 

a. The group discussed the importance of the phrase "becomes operational." 

Brendan McCarthy stated that SB 83 8 is unclear on who has 

implementation authority. 

b. The group identified some of the issues associated with determining a 

facility's operational date. Discussed what type of investments in an 

existing facility could cause it to be considered a new facility for the 

purposes of the RPS. Juliet Johnson of the PUC raised the point about if a 

facility were to switch fuel sources. 

c. The group discussed how the California RPS has approached this issue. 

d. Megan Decker commented that Oregon should try and encourage 

investment in new facilities, so should carefully define "capacity" and 

"efficiency". Should keep this distinction simple. 

e Brendan McCarthy suggested that other facility permits, such as DEQ 

permits, could be an alternative to basing the decision purely on 

investment levels. 

f Jeff Bissonnette stated that he was uncomfortable using the investment 

level as the bar. He gave the analogy that a new engine is not the same as a 

5 
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RPS 2010 Advisory Committee Meeting 

M~eting #4 Minutes 

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Oregon Dept. of Transportation, Portland, OR 

Attachment E 

Page 53 

new car. He added that the policy behind the RPS is not financing and 

jobs. 

4. Hydroelectricity: efficiency v. capacity 

a. Kate Miller looked at the proposed federal RPS. She pointed to the FERC 

guidance on this issue. The FERC defmes what efficiency upgrades are 

not. · 

b. Rick Oliver raised the question of what constitutes the "generating unit" 

for a hydro facility. 

c. Brendan McCarthy provided three scenarios where PGE is dealing with 

this issue. 

d. The group discussed how best to establish the baseline. 

5. Oregon share of the federal project upgrades 

4. Bundled/Unbundled REC issues · 

1. Jason Heuser described EWEB > s power swap agreements> which do not create 

NERC e-tags> and why EWEB believes the QE should still be counted as bundled 

RECs. Kip voiced his concern that this situation aligns with the statute. 

5. Stranded Generation 

1. Kip reviewed some of the options that the group has discussed before. 

a. WREGIS. PCR 192 will be discussed at an upcoming WREGIS meeting. 

The group would need to consider any fmancial implications of going this 

route. 

i. Brendan McCarthy said he was concerned that the rulemaking 

would end before the group resolved the issue. 

b. Interim system. Kip is concerned with this route for several reasons> 

including potential double-counting of RECs> and establishing an end 

date. 

1. Betsy Kauffman said that the ETO was very interested in this issue 

because the ETO is looking at developing a tracking system for 

contractual RECs. The systems are not entered into WREGIS due 

to associated costs. 

ii. Jeff Bissonnette suggested that there may be other ways for RECs 

to benefit ratepayers. Could be sold to voluntary markets. 

111. Several group members objected to the idea of a parallel tracking 

system with no end date. Specifically, because of verification 

issues. 

iv. Kip added that voluntary programs migrated to WREGIS in 2008. 

He also stated that rooftop solar in California was granted a special 

waiver. He said that small hydro runs into the same problem. The 

RPS was designed for utility-scale tracking. 

v. One potential problem with using attestations· is the lack of clarity 

of whether these would go to ODOE or the PUC. Kip does not 

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RPS 2010 Advisory Committee Meeting 

Meeting #4 Minutes 

9:00am to 3:30pm 

Page 54 

Oregon Dept. of Transportation, Portland, OR 

c. NARR. 

know the answer, but pointed to the fact that some utilities do not 

report to the PUC. 

i. The group decided that it would be best to wait on this option until 

after "WREGIS makes a decision. 

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Attachment E 

Page 55 

RENEW ABLE ENERGY PRODUCTION TAX CREDIT: 

INSTRUCTIONS FOR REQUESTING CERTIFICATION OF 

INCREMENTAL HYDROPOWER PRODUCTION PURSUANT 

TO THE ENERGY POLICY ACT OF 2005 

FEDERAL ENERGY REGULATORY COMMISSION 

OFFICE OF ENERGY PROJECTS 

DIVISION OF HYDROPOWER ADMINISTRATION & COMPLIANCE 

Updated & Posted on FERC;s website March 2007 
UM - PGE 2012 RPS Complicance Report 

ENERGY POLICY ACT OF 2005 

RENEW ABLE ENERGY PRODUCTION TAX CREDIT 

Attachment E 

Page 56_ 

This paper was prepared by Commission's staff and does not necessarily reflect the views of other 

members of the Federal Energy Regulatory Commission. 

EP Act 2005 -Hydroelectric Tax Credit 11 
UM __ - PGE 2012 RPS Complicance Report 

Attachment E 

Page 57 

SUlVIMARY 

Section 45 of the Internal Revenue Code of 1986 provides a renewable energy tax credit 

to owners or operators of electric generation facilities that produce electricity from 

"qualified energy resources" at "qualified facilities," placed into service by specified 

dates. 

Section 1301 of the Energy Policy Act of2005 amends Code section 45 to apply the 

credit to incremental production gains from efficiency improvements or capacity 

additions to existing hydroelectric. f?,qiij.#¢§f'pJ~{,£~4·ipJq service after August 8, 2005 and 

· before January 1, 2009. . +x{:.:i'1'./:;;:;~·:"t';;~~:fi7i?f::~!'~';,':;z~~'I!M\<: .. 

~;:~~:!o;~:~d~iiflt~~i~it~6~~~i~~;:;~~:;;~d:::l 

at the fac11ity attrtbutagJ~i;t<?.!4~t~ft19~enqX2iWPt~ye~~~t~i~f:,<i,R~1,tf~ns ofcapaclty" placed 

m service after Augui:fj~,~~'tti1~~~~trm1t~~~~i~J~l"Il~!v, 

In this paper we will e,~P,l~:ip, @.~:!~qpiryJ:rie,:qt§ qfi'!Q¢ §t{;C.f¢,gitfo#wcremental • .··. ;.:'>' 1 · ·' \ .... ,.. .. ·. :,·· ·· •· ;.; :_~ (,\•·-~.:· :' ... ,, .:• ·:·:r· · ·:, · . · ':"·'; .... '.' '.~·.- .. · )·.-:>·~.:;~.::-::.,.·.;, t .~-:- • . . :·\. ' • ,. ·: ·~ r. • • 

hydropower generatwti~from effi¢1eP.,py l111-P,t"O.Y¢'m~f1t&·~~g\t1J.e type· of informatwn the 

~;=!s~~t~~~~i\~l~~l~~~~~i;:~~~~~.~~~~o~ . , .."'~:'i;}~~l~ll;; ¥~:;,i "'"'#' 

EPAct 2005 -Hydroelectric Tax Credit iii 
UM - PGE 2012 RPS Complicance Report 

CONTENTS 

Attachment E 

Page 58, 

Page 

I. Changes to the Internal Revenue Service Code ...................................................... 1 

II. Certification Procedures ........................................................................................ 2 

A. Certification of Baseline Annual Hydropower Production ............................ 2 

B. Percentage of Annual Hydropower Production Attributable to Efficiency 

Improvements or Additions of Capacity ..................................................................... 3 

ill. Instructions for Requesting Certification.: .......................................................... 5 

A. Historic Average Annual Production (baseline): ...................... 5 

B. Percentage of Attributable to 

Efficiency ....... ; ........................... 5 

EP Act 2005 -Hydroelectric Tax Credit iv 
UM _- PGE 2012 RPS Complicance Report 

Attachment E 

Page 59 

MW. ...... A .... ,.44-CQC .. ± .. k. ... ... . ...... 44 .... $ .. 2424!4#444 $ .. ..%#¢. .4 

ENERGY POLICY ACT OF 2005 

RENEW ABLE ENERGY PRODUCTION TAX CREDIT 

I. Changes to the Internal Revenue Service Code 

Section 45 of the Internal Revenue Code of 19861 provides a renewable energy 

tax credit to owners or operators of electric generation facilities that produce electricity 

from "qualified energy resources" at "qualified facilities," placed into service by 

specified dates. 2 The credit, which is indexed for inflation, is currently about 1.8 cents 

per kilowatt-hour (kWh). 

1 26 U.S.C. § 45 (1994). 

2 Qualified energy sources include· wind, biomass, geothermal energy, solar 

energy, small irrigation power, municipal solid waste and poultry waste brought mto 

service before specified dates. 

3 Pub. L. No. 109-58 § 1301, 119 Stat. 594, (2005), and Pub. L. No. 109-432 Title 

II, § 201, 120 Stat. 2922, (2006). 

4 Section 1301 modifies the definition of "qualified energy resources" in Code 

section 45( c )(1) to include "qualified hydropower production." The latter term is defined 

in new subsection 45(c)(8). 

5 26 U.S.C. § 45(b)(4)(A). This credit rate also applies to certain other qualified 

facilities not relevant here. 

EP Act 2005 -Hydroelectric Tax Credit 1 
UM - PGE 2012 RPS Complicance Report 

Attachment E 

Page 60. 

ten years, and begins on the in-service date of the qualifying efficiency improvement or 

capacity addition. 6 , 

Section 1301 amends Code section 45 to provide that the incremental hydropower 

production at an existing facility for any taxable year is equal to the percentage of 

average annual hydropower production at the facility attributable to the efficiency 

improvements or additions of capacity placed in service ·after the date of enactment, 

determined by using the same water flow information used to determine an historic 

average annual hydropower production baseline for such facility. The incremental 

hydropower production may not be based on operational changes unless they are directly 

associated with the effiCiency improvements or additions of capacity. The Commission 

is required to certify the percentage and the baseline. 7 

In order for a capacity additiontQ~.,R9Jl:llY(]roelectric dam to qualify, the dam 

must be licensed by the Commi~~!gB;~p~y~,~#eBPJ·~s~q,jl:lto service before the date of 

enactment, and not have proqv.9~~-,p.~\¥¢(q#th,e.4~t~~of.~~,appnent. In other words, the 

dam must have been place4Jn:S,ecyi~eprio~tQ,.t11e~nadriiell1:;o£EPAct 2005, but did not 

generate hydroelectric P8~~~:\:~f9g~,t~at~~~fi~~i§~ is'·~~!~~94.;~,.ff _licensed project. 

There can be no enlargew.~;n,tqf.J~.~4Jivet~I9P,Strq'Ctuf.t:\~q9.-BSAAG.ttpn or enlargement of a 

~~:. ;h::;~~~~ an~~~~~,~j;~lttd~(i~~¥~·~~~~:::~i~:~th!~t . documentatwn from the,q<?nJ.W}BS~Q,ll(b~c<tuS.¥ -.reyi~~q,.Go4~'~@9t1o,n45 does not requrre 

II. :~rtifi::~!i{~~. :. . •i !.(~ 

hydropower production baseline, referrfiig:'(irilyt6'the use of "water flow information." 

Water flow often does not correspond directly to power production, because many 

projects are operated in a storage and release mode, have instream flow, fish passage, or 

other flow requirements that preclude or restrict generation at certain times to address 

environmental concerns, and because flows at certain times of the year may exceed the 

hydraulic capacity ofthe project's turbines. 

6 New subparagraph 45(d)(9), added by EPAct 2005 section 130l(c)(4). 

7 Code section 45( c )(8)(B)(i) and (ii), as revised by EP Act 2005 section 

130l(c)(3). 

8 Code section 45(c)(8)(C), as revised by EPAct 2005 section 1301(c)(3). 

EP Act 2005 -Hydroelectric Tax Credit 2 
UM __ - PGE 2012 RPS Complicance Report 

Attachment E 

Page 61 

. x ... e::e. . . .... . . ....... . ~zeaoMx ... . . oz... x. .& . 24 .k 

Under these circumstances, we will not establish a formula for calculating the 

baseline. Rather, licensees should submit for Commission review and certification the 

historic average annual hydropower production baseline they believe to be appropriate 

for the facility in question, along with the supporting calculation and water flow data. 

The Commission may request additional or revised data if that is necessary to complete 

its analysis. 

B. Percentage of Annual Hydropower Production Attributable to 

Efficiency Improvements or Additions of Capacity 

Calculating the percentage of annual hydropower production attributable to 

efficiency improvements or additions to capacity is a straightforward matter once 

project's average annual generation wi,tl;q~.~d:wit:llg11t the efficiency improvements or 

capacity addition is establis~;,~f~!'i'i';dd~~?i >;%{';;~%~~,., 

: Section 1301 does .. A9J'\~efl#.~:t:':~fiic~~gsy;;Wi:Pi:.9;yeiJ,i~l,i~~." or "additions of 

~:~~!; :;~~~~;,~~ilf~~;,~ti!t;lf.6!~~1~~!~iffi~:~:~;ted with the 

improvements" to encoijip~&s aa:Qif!cyp.al'\ge:q.¢r~'ion :(tori;l,.'.~X.isting''~quipment in the form ~,!.~·.:o·.·,,'.'. :o•·;·_'.;J"•.•:·:y·.::.'{';_,. L.:c:-'·:··.1:.-.'::0.'::!.) •• .. '.\·· ·/'··:·'·'/ '•··:·-_:·.'/ .·;·.-:~ 

of up grades to genera~~#iq~;;wr1)1jfe,s}:~ E~ampl~si'inc.lud~ i~Wffidii1!fgenerators, replacing -· -,\·-~-;-,.- .. _, -_··~~-':··:-:'-.:;}----_,.. '-:.·.-'.! ,_ ·.' '·'. ,_; .. _, \r .~ .. • .. ~,. ::.'·\:·i ::·'.··.'-..·.,,~,··:·'··. ,,·· .. --' 

turbines with more efficien,t,uiiits~1 :ari.d''coinputep.~iri:g',PQi.i~d1\offittbines and generators 

:~:=~=~~~llflill&~illit(lf:r:~~::ple of addition of capacity is,;§f;.§~t~Jl~ti9.~d'~tJ~~iltijpPt~ill flp·\Y.~~~#ating unit. Examples of 

operational changes not dif~'9tly assp~i'ate9''\yit1f'~ffi2't¢riby;i~pfovements or additions to 

capacity include raising the }Jbri:4:'1~v~ltb W,c'r~~s-~'h¥a9.~;:~cfreducing spill flows required 

for environmental protection. ::\c;·.~_.;\·;,,·,.;,!:::="fi.:/i~~;.:~/~;~i:.,;''/ .. / . 

Revised Code section 45 requires the Commission to certify the percentage of 

annual power production attributable to the efficiency improvements or additions of 

capacity. We interpret this to require us to certify the percentage just once, using the 

established average annual generation baseline and the incremental generation calculated 

when the project operator seeks authorization for the efficiency upgrade or addition to 

capacity. For instance, if the historic average annual generation has been 1,000,000 kWh 

and an efficiency upgrade would enable the project to generate 1,100,000 kWh, we would 

9 Because new Code section 45(c)(8) distinguishes "operational changes" from 

"additions of capacity," we conclude that Congress did not intend to apply the credit to 

additions of capacity resulting solely from operational changes such as increasing the 

reservoir level or switching from run-of-river to peaking operation. 

EP Act 2005 -Hydroelectric Tax Credit 3 
UM - PGE 2012 RPS Complicance Report 

Attachment E 

Page 62 · 

certify that ten percent of the average annual generation is attributable to the upgrade. 

We will allow a one-time recertification of the percentage if applicants can demonstrate 

such a need due to fluctuations in generation attributable to the efficiency improvements. 

EP Act 2005 -Hydroelectric Tax Credit 4 
UM __ - PGE 2012 RPS Complicance Report 

Attachment E 

Page 63 

ML# ............. Xi ... .$$$$ . ........... $ .... .. . ........ ;: 

ill. Instructions for Requesting Certification 

Licensees and exemptees that intend to seek a renewable energy production tax 

credit for efficiency improvements or additions of capacity at existing facilities pursuant 

to Internal Revenue Service Code section 45 are required to provide the Internal Revenue 

Service with certification from the Commission. The Commission is required to certify 

· the "historic average annual hydropower production" and the "percentage of average 

annual hydropower production at the facility attributable to the efficiency improvements 

or additions of capacity" placed in service after August 8, 2005 and before January 1, 

2009. For this purpose, licensees should submit a request for certification that includes 

the following information: · 

A. Historic Aver:!i£~~~~~~~1~1:~~\~~t~uction (baseline): 

I. A calculatiqp) l:)fth,dits!ol:ic·~yerag~i.~tlliu~l;h:ydropower production 

:._;,{;.}~'{::: --~ .. · 

. :;~t: \'j~!/~, .. -:~:::.: ~ >::: 

1. 

2. 

improvements to thb':tlp;gr£dgd:~~ri6f.ating equipment and the anticipated 

annual generation for the facility based on the same water flow data 

used to support the calculation of Historic Average Annual Hydropower 

Production baseline. 

3. Calculations showing the percentage of average annual hydropower 

production attributable to the efficiency improvements or additions of 

capacity. 

4. Proposed in-service date. 

Any requests for Certification must be filed with the Commission's Secretary, in 

one original and 3 copies. The applicants must allow for no less than 90 days for the 

Commission to process their request. 

EP Act 2005 -Hydroelectric Tax Credit 5 
Sample Order 

EP Act 2005 -Hydroelectric Tax Credit 

UM - PGE 2012 RPS Complicance Report 

Attachment E 

Page 64, 

6 
UM _- PGE 2012 RPS Complicance Report 

Attachment E 

Page 65 

........... R ... )¢1 .... :;: .. . ...... "- .. ($.6 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Hydropower Company Project No. 12345-001 

SAMPLE 

ORDER CERTIFYING INCREMENTAL HYDROPOWER GENERATION 

FOR IRS SECTION 45 PRODUCTION TAX CREDIT 

UNDER SECTION 1301(c) OF THE ENERGY POLICY ACT OF 2005 

(Issued XXXX) 

. : _ .. ·._:::i?:t~.\t./~~li}t~~&;f~~:-~~~::4~~-hs-~~~:)._~- '·:· 

On [Month, Day, Year],[Qp±Q,~piiyft~~~~@.#]t'l~§~gs,~~ for the [Project Name, FERC 

No. xxxxx], located on [Na~~l;§:~~~~!~fi1?§~g~JH[,S9;Wio/];;:t§l~t,e], filed a request for 

certification for a renew(lbJ~'~rl~tiDf·Pf()4p¢ti§#.J~*Lpi6,qtt.f9~'~:fficiency improvements or 

::;:::~J[1tii~I!,~I~1Wl=:i~ode 

production" and the "~~f9~J.it~~~~Q,~.~Y-~ra!~~ ~p!lval,,~Yqrpi>cuy~[:B£gduction at the facility 

attributable to the effic~~ri,c)(@ptq:¥~ri:leP:ts pr aqciificiP.&.,9f,~apact(:yi:' placed in service 

::::::::~:s1~~f~f;l!!!:!;~~!tls~~ris r~~d to cmuy 

(A) Based on our rev1~w,.9Ub.-~#if.9:i;i;l.l~tio.Q.:rii<_h~ided by the licensee/exemptee 

we certify the following: · ,, ;~;;::;_;{f,i;\i;·i\;;fJt!~lt~r;,t~~\~;~;:-P'~!"'~-· . 

EP Act 2005 -Hydroelectric Tax Credit 7 
UM - PGE 2012 RPS Complicance Report 

Attachment E 

Page 66. 

(B) This order constitutes fmal agency action. Requests for rehearing by the 

Commission may be filed within 30 days of the date of issuance of this order, pursuant to 

18 C.P.R.§ 385.713. 

[Official's Signature] · 

EP Act 2005 - Hydroelectric Tax Credit 8