### June 1, 2013 

### Email I US 

### Mail Portland General Electric Company 121 SWSalmon Street • Portland, Oregon 97204 PortlandGeneral .com



### Public Utility Commission ofOregon 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 ofPGE's Renewable Portfolio Standard Compliance Report
. The Report is submitted pursuantto 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 ofhydro 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 ofthis 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 beenredacted. Hardcopies ofthe unredacted pages have beenplaced on ydlowpaper in a separately sealed envelope bearing the legend "CONFIDENTIAL." Please do not place the confidential portions onthe OPUC website, nor release it to anyone outside the Public Utility Commission Staff. Please store the hardcopy in a locked file cabinet. Ifyou are unable to honor these requests, please notify us immediately. 

### Ifyou 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



### Asan introduction andsummary of the Compliance Report, answer the following questions: Why is PGE submitting a Compliance Report? What information was used as the basis ofthis 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 mostrecent RPS Implementation Plan. Did the companymeet its Renewable Portfolio Standard (RPS) target, and ifnot, describe indetail why not? Yes, PGE has metits 2012 Renewable Portfolio Standard (RPS) target. The compliance details are providedin this report. Provide thefollowing information in response to the requirements of OAR 860-083-0350:

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

### The total number ofmegawatt-hours sold to retail electricity consumers covered by ORS 469A.052 by the electric company or sold 

### in the service areas ofeach electric company covered by ORS 469A.052 by the electricity service supplier. Response: 

### For 2012, the total number ofmegawatt-hours sold to retail electricity consumers was: PGE's Total Billed Load: 17,975,810 megawatt-hours. Source: 2012 PGE PERC Form 1 (Page 304, Row 41, Column (b)).

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

### The total number ofrenewable energy certificates, identified as either unbundled orbundled 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 meetthe renewable portfolio standard requirement for compliance year 2012.


### OAR 860-083-0350(2)(c) The total number ofrenewable energy certificates, identified as either unbundled orbundled certificates, acquired onor before March 31 ofthe year following the compliance year and used to meetthe renewable portfolio standard. 

### Response: There are no bundled certificates acquired in 2013 that will be used to meetthe renewable portfolio standard requirement for compliance year 2012. There are 140,800 unbundled certificates acquired in2013 that will beused to meetthe renewable portfolio standard requirement for compliance year 2012. 

### OAR 860-083-0350(2)(d) The total number and cost ofunbundledrenewable energy certificates, identified as eitherbanked or **non~banked** 

### certificates, used to meetthe renewable portfolio standard. 

### Response: The table below shows the total number and cost by facility ofthe 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 ofbanked bundled renewable energy certificates that were used to meetthe renewable portfolio standard. 

### Response: The total number ofbanked bundled renewable energy certificates that will be used to meet the renewableportfolio 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 ofrenewable energy certificates, identified as either bundled or unbundled certificates, issued inthe compliance year that were banked to serve Oregon electricity consumers. Response: There are no unbundled certificates that were issued inthe compliance year that were bankedto serve Oregon electricity consun1ers. As ofthis filing, there are 2,564,331 bundled certificates that were issued for the compliance year 2012 thatwill be banked to serve Oregon electricity consumers. See the 2012 column inAttachment C for detail by facility.

OAR860-083-0350(2)(g) For electric companies, unless otherwise provided under subsection (2)(k) ofthis rule, the total number ofrenewable energy certificates included in the rates ofOregon retail electricity consumers that were sold since the last compliancereport, including: (A) The names ofthe associated generating facilities; and (B) For eachfacility, the year or years the renewable energy certificates were issued. Response: There are no renewable energy certificates included inthe rates ofOregon retail electricity consumers that were sold since the last compliance report.
OAR860-083-0350(2)(h) Unless otherwise providedunder subsection (2)(k) ofthis rule, for each generating facility associated withthe renewable energy certificates included in subsections (2)(b), (c), (f), or (g) ofthis rule the following information: (A) The name ofthe facility; (B) The county and state where the facility is located; 

### (C) The type ofrenewable resource; (D) The total nameplate megawatt capacity ofthe facility; (E) For an electric company, the Oregon share ofthe nameplate megawatt capacity ofthe facility; (F) The year ofthe first delivery ofqualifying electricity or the first year ofthe contract for thepurchase ofunbundled renewable energy certificates; and (G) The duration ofthe contract orthe amortization period ofa facility owned by the electric company ortheplanned lifetime ofa facility ownedby the electricity service supplier. Response: 3

### See Attachment A. 

### OAR860-083-0350(2)(i) The amount ofalternative compliance payments the electric company or electricity service supplier elected to use or was required to use to comply withthe applicable renewable portfolio standard. 

### Response: There are no alternative compliance payments that PGE elected to use or was required to use to comply withthe applicable renewable portfolio standard. 

### OAR 860-083-0350(2)(j) For an electric company, sufficient data, documentation, and other information to demonstratethat any voluntary alternative compliance payments were

# areasonable compliance method. 

### Response: PGE will notbe making any voluntary alternative compliance payments. 

### OAR860-083-0350(2)(k) Documentation ofuse ofrenewable energy certificates from the system under OAR 330-160-0020 established for compliance withthe applicable renewable portfolio standard. 

### Response: The attached WREGIS report (Attachment B) shows all renewable energy certificates to be used to meetthe 2012 renewable portfolio standard. The RECs are currently in an active sub-accountnamed "2012 ORRPS." Within 30 days ofthe approval ofPOE's RPS Compliance Report by the Commission, the RECs will beretired to a retirement sub-account named "ORRPS 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 ofany material deviations from the applicable implementation planfiled under OAR 860-083-0400, as acknowledged bythe Commission. 

### Response: The table belowpresents 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 ofeconomic recession. 

### It should also be noted our 2011 Compliance plan listed a similar drop of 135,883 for the year 2011 versus what hadbeenpredicted in 2009. 

### 4

### Another material difference is the number ofunbundled RECs used for compliance. As we stated 

### in our 2011 Implementation Plan: PGE intends to continue monitoring REC markets and maypurchase or sell bundled or unbundled RECs inthe market whenprice is perceived to be a good value inrelation to other means ofachieving 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 ofour bundled RECs for use in later compliance years. One other difference- also noted inthe 2011 Compliance Plan, is the inclusion ofthe RiverMill and Sullivan hydro upgrades. The number ofRECs are not material in total REC numbers, but are called out for completeness. PGE hadbeen including hydro upgrades ofvintage 1999 or later inits IRP and Implementation Plan filings. Following those filing we determined that the appropriate year for including suchupgrades was 1995 (see ORS 469A.020- Qualifying electricity; age ofgenerating facility); resulting in the inclusion ofthe two additional facilities. Again

- the total number ofRECs here is small; 3,240 (about 113 MWa). One other note for the Sullivan project- some ofthe RECs generated there are counted as facility upgrades, while some are counted as low-impact hydropower RECs. The table belowincludes the project broken out in the two separate categories. PGE is limited to 50MWa oflow-impacthydropower, withportions ofthe total coming from Sullivan, Pelton, and Round Butte. The other differences are mainly related to the increased use ofunbundled RECs, and lowerprojected need. This introduces timing issues in REC retirement. Our initial forecast relied on RECs that would be generated in2009, however due to the factors discussed above, 2012 compliance only relies onRECs generated in 2008 or earlier. Thus we do not use any RECs from Biglow 2, and lower amounts from hydro upgrades as well as Sunwaythan initiallyprojected. 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) 

### 5Willamette 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 ofbundled 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 ofcompliance. Response: PGE's projected annual revenue requirement for 2012 is: $1,709,111,606. Source: Table 1- Base Rates Estimated Effect on CustomerTotal Electric Bills 2012 COS Only

PGE's total cost ofcompliance for 2012 is: [2(d) 

## +2(m)] = 

### $3,859,811 Cost ofcompliance as percentage ofrevenue requirement is: 0.23% OAR 860-083-0350(2)(o) For each electricity service supplier, its total cost ofcompliance, its average cost ofcompliance, 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 ofthe use ofthe renewable energy certificates and alternative cost payments consistent with OAR 860-083-0300(3) ifthe cost limit in ORS 469A.l00(1) is reached for the compliance year. Response: 

### The cost limit in ORS 469A.lOO(l) was notreached for the 2012 compliance year.
OAR 860-083-0350(2)(q) 

### For each electricity service supplier, an accounting ofthe use ofthe renewable energy certificates and alternative costpayments consistent with OAR 860-083-0300(3) ifthe 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 ofall 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 ofbundledrenewable 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 onits web site the public portion ofthe four most recent annual compliance reports required under this rule and provide a copy ofthe most recent such report to any personupon request. The public portions ofthe most recent compliance report mustbe posted within 30 days ofthe Commission decision 

### in section (5) ofthis rule. The posting must include any Commission determinations under section (5) ofthis rule. Response: 

### PGE will comply with this requirement within 30 days ofthe Commission decision.



### 7

### OAR860-083-0350(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 informationmustbe provided within 90 days ofthe Commission decision in section (5) ofthis 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) ofthis rule. Response: 

### PGE will comply withthis requirement within 90 days ofthe Commission decision.

8

# PGE 2012 RPS Attachment AAttachment A

lWilmpactliydrosubjett to50t..maCaP. *Assoclatedwithhydroefficlencyupgrades. "*QF=QualifyingFacility

NM=NetMetering PPA = PWier Purchase Agreement SVP"' SolarVolumetric 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

NoCertificates in Subaccount (Continue)

Page 2 ofII Brown Lake GeneratingStationBrown 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 NoCertificates in Subaccount (Continue)

W876

W1492

Page 3 ofll PeltonPelton Gen 3

Miller CreekMiller Creek Generating Facility Unit 1

Brown Lake GeneratingStationBrown 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 NoCertificates in Subaccount (Continue)

Page 4 ofll 2012 OR RPS Round Butte W879 -Round

W1909 Butte 3 Brown Lake GeneratingStationBrown 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

NoCertificates 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

NoCertificates 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 NoCertificates 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

NoCertificates 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

NoCertificates in Subaccount (Continue)

Page 9 ofll River MillRiver Milll
MillerCreekMiller 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 NoCertificates 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 NoCertificates 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 COAR 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 retred 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 dueto issues w.th WREGIS's abolily to cmate these REGs.. PGE isworking 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 includedfrom 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 DUM

__- PGE 2012 RPS Compliance Report Attachment D Page 1

As part ofthis 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 afterJanuary 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 underthe statute 3 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 ofthe 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 ifthe electricity is attributable to efficiency upgrades made on or afterJanuary 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 330-160-0050UM

__- PGE 2012 RPS Compliance Report Attachment D Page2
capacity ofthe diversion structure and PGE did not appropriate additional waterfrom 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 ofwhich was significantly influenced by a smaller group of activists, utilities and customer representatives which called itselfthe "RPS Discussion group." The REWG grew from Governor Kulongoski's 2005 Renewable Energy Action Plan ("REAP"). The REAP specifically called for the creation ofthe 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, letterfrom 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 ofAshland.UM

__- PGE 2012 RPS Compliance Report Attachment D Page3



### "incremental electricity produced as a result of

### improvements to existing hydroelectric generation." 8 A letterfrom the RPS Discussion Group to the chair ofthe REWG, Mike McArthur and Bill Drumheller, noted whether utilities would be able to count 

### "incrementalimprovements at existing hydroelectric facilities." 9 In a tracking document developed by the REWG, the term was 

### "increment ofimprovement 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 ofwording 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 ofthe 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 atechnical 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 ofwater, 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 ofthe 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 otherthan 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 ofwater. 16

PGE's improvements at Faraday fall within the bounds ofthis rule. The improvements were made to existing generators and did not involve increased impoundments, increased appropriation or increased diversions ofwater.

This is not the end ofthe 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 otherthan 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 ofthe 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 whetherthe

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 ofwater 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 underthe 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 ofthe term uprate "which typically refers to a capacity increase" and that there are limited opportunities for efficiency increases ofthe 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 ofIncremental Hydropower Production Pursuant to the Energy PolicyAct 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 ofturbines

.... 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 ofjustifiable efficiency numbers was based on "best available evidence." As the email notes, "Additional information about the pre-uprate condition ofthe 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 have 22 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 ofwhich 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 RNWP [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 forthe largest portfolio of hydropower in the nation, overseeing the design work on generating units in a wide variety ofvintage, 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-uprate condition ofthe 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 ofthe Electric Utility, City ofAshland Subject: Draft ofPotential RPS Language At the conclusion ofthe July 11 meeting ofthe Renewable EnergyWorking 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 OregonRPS. As you know, consumer-ownedutilities are governed by our local boards and commissions and largelypurchase our electricitythrough federal contracts with BPA. 

### Therefore, webelieve that any Oregon RPS legislation should have a unique section dealing with consumer-ownedutilities as is the case generally with federal and state legislation. Since the JulyREWG meeting, we have been working to outline what that section should look like. Ourproposal is described below. We are still working on some ofthe details and will provide those to you as we continue to work with our associations and members onthis subject. 

### Itis also important to recognize that public power is in the process ofnegotiating 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 ofour communities. Webelieve ourproposal accomplishes the Governor's goal to encourage the continued development ofnew renewable resources andreduction ofgreenhouse gases while recognizing the unique nature ofconsumer-owned utilities, our contractual relationship with BPA, and our existingrenewable resource development. 

### SECTION A.) 

### Purposes and Policies: The Legislative Assembly declares that it is thepurpose of this title to: 1.) Encourage cost-effective conservation and efficiency 

### inthe use ofelectric power; 2.) Encourage the development ofcost-effective renewable resources; 3.) Assure customers an adequate, economical, and reliable power supply 4.) Recognize that consumer-ownedutilities purchase all ormajorportions of their electricity supplyfrom the Bonneville Power Administration under long-term federal contracts; 5.) Recognize that virtually all ofthe existing Federal Base Systempower comes from resources that do not contribute to greenhouse gas emissions; 6.) Recognize that increasing development ofrenewable resources by consumerowned utilities will require new BP A renewable products, adequate and affordable transmission access and the availability ofthe 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 ofconsumer-owned utilities and their governing bodies to respond to their consumers; 8.) Recognize that communities served by consumer-owned utilities located in various parts ofthe State ofOregonmay differ intheir needs and desires concerning the provision ofelectricity and related products and services; 9.) Retain local control over consumer-owned utilities 10.) Preserve, clarify, and as providedherein, enhance the rights and authorities ofconsumer-owned utilities and their governingbodies. 

### B.) Eligible Resources: 3. Eligible resources include small hydro, solar, wind, biomass, wave/tidal, landfill gas, plus

- a.) Hydro efficiencyupgrades (including BPA andthe Mid-Columbias) b.) TierTwo renewable product and renewable portion ofany other BPA 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 ofnewrenewable resources i.) Smallhydro (30 MW or less) 

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

### k.) IGCC with sequestration when used as part ofa carbonreduction program 4.) Eligible renewable resources and tags include those from within the Western Interconnection 5.) Eligiblerenewable resources include thosebrought on line orunder contract after the effective date ofthe Northwest Power Act. 6.) Small, community scale renewable projects (1 0 MW or less) canbe counted as extra credit (150%) 

### C.) All Consumer-owned utilities: By 2012, each COUlocalboard, through a public or memberprocess, shall adopt and implement a local utilityrenewable resource policy giving priority to the purposes in Section A ofthis title. As part ofthat policy each COU shall consider andmake a specific determination whether to implement either: 1.) inclusion as part ofits resourceportfolio, in an amount determinedby the local board, a BPA renewable product, EPP, or otherrenewable resource, or 2.) a green pricing ortag program for its customersUM _- 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 priorityto the purposes in Section A ofthis title. A localrenewable resource standard is deemed to meet the intent ofthis title ifit targets either: 1.) 

### 25% ofloadwith eligible renewables by2025 or 2.) 60% ofload growthwith eligible renewables by2025 Adoption ofa local alternative standard to (1.) or (2.) must be accompanied with findings and a determination that the standard is consistentwith Section A ofthis title. The board may adjust the standard ifit determines through a public process and with appropriate findings that one ormore ofthe 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 utilityto reduce the amount ofload servedbyBPA from the federal base system including butnot limited to Tier One. No utility shall berequired to forgo any generating resources owned orunder contract as ofthe date ofthis Act norto acquire anyresource or credits that would cause the utilityto haveresources or credits in excess ofthe cumulative electric demand ofits 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 certificationby COUboard throughpublic process 3.) Offramp for force majuere 4.) Offramp for lack oftransmission 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 legaltools)UM

__- PGE 2012 RPS Complicance Report Attachment E PageS 

### Myname is John Carstensen, I am the Thermal ProjectManager for the Idaho Power Company. Idaho Power is a 10% owner ofthe BoardmanPower Plant. Ofthe approximately 90,000 lbs ofmercury emitted each year from coal fired utilities in the US, almost 92% is emitted byEastern utilities. Boardman emits approximately 200 lbs/year, about 1/4th of 1% ofthe mercury emittedbyU.S. coal fired utilities. The Idaho Statesmanreported onMonday ofthis week that there is a cement plant in Eastern Oregon that emits over 2,100 lbs ofmercury each year, about 10 times the emissions of Boardman. Because ofthe low levels ofmercury in the coal burned at Boardman, precise measurement is difficult at best. Controlling orreducing 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 utilityboilers. The Federal EPA cap and trade program thathas been so successful for 

### S02 was adopted for mercury. The huge success ofthis program lead to over-compliancebyutilities. For mercury, the EPA established the cap and trade program to effectivelyreduce mercury emissions while allowing utilities to determine the most cost effective means. By replacing the cap andtrade program to command and control, Oregon will lose all ofthe costbenefits 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. Bybasing limitations ofemissions on emotion, unnecessary costs and burdens willbe placed on businesses and especially onthe customers least able to paythe utilitybills. Therefore it is ourpositionthat the DEQ should use soundjudgment andproven science to determine the regulations to control mercury from Boardman. Thankyou for your time.UM

__- PGE 2012 RPS Complicance Report AttachmentE Page6



### September 6, 2006 To: Mike Grainey and Bill Drumheller From: Tom O'Connor Subject: Draft ofPotential RPS Language Below is a more fleshed outversion ofthe outline Don, Dick andI submittedto the AugustREWGmeeting. This has notbeen 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 draftyour strawman.
SEC. 

### 1. Purposes and Policies: TheLegislative Assembly declares that it is the purpose ofthis Actto: 1.) Encourage cost-effective conservation and efficiency inthe use ofelectric power; 

### 2.) Encourage the development ofcost-effective renewable resources; 3.) Assure customers an adequate, economical, and reliable power supply 4.) Recognize that consumer-ownedutilities purchase all ormajor portions of their electricity supply from the Bonneville PowerAdministration under long-term federal contracts; 5.) RecogniZe that virtually all ofthe existingFederal Base Systempower comes from resources that do not contribute to greenhouse gas emissions; 6.) Recognize that increasing development ofrenewable resources by consumerowned utilities will require new Bonneville PowerAdministration renewable products, adequate and affordable transmission access andthe availability ofthe Federal hydropower system and conventionalresources for shaping and firming; 7.) Preserve and enhance the ability ofconsumer-owned utilities and their governingbodies to respond to their consumers;
·8.) Recognize that areas servedby consumer-owned utilities located in various parts ofthe State ofOregon 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 ofconsumer-ownedutilities andtheir governing bodies. SEC. 2. Definitions 1.) "Consumer-ownedutility" means a municipal electric utility, a people's utility district or an electric co-operative as defmed 

### in ORS 757.600. 2.) "Covered consumer-ownedutility" means a consumer-ownedutility that serves over 50,000 retail electric customers in Oregon onthe date ofthis Act. 3.) "Eligible renewable resource" means (a.) electricity from a generating facility powered by a renewable resource that commenced operation after the passage ofthe RegionalActwhere the facility is located within the boundaries ofthe Western Energy Coordinating Council (b.) incremental electricityproduced as a result ofimprovements to existing hydroelectric generation or combined heat andpowerprojects owned orUM

- PGE 2012 RPS Complicance Report



### operated by a utility, the federal government, or any other entity within the boundaries ofthe 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 BonnevillePowerAdministration (e.) electricity neededto shape, firm, or integrate an eligible renewable resource used to meetthe requirements ofSection 3 and 4 

### ofthis Act (f.) electricity from a customer-owned eligible renewable resource through a netmetering 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, ortidalpower; 

### (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 orfield residues or dedicated energy crops orblack liquor but does not include woodproducts 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 memberprocess, shall adopt and implement a local utility renewableresource policy givingpriority to thepurposes in Section 1 ofthis Act. 2.) As part ofthatpolicy each consumer-owned utility shall consider and make a specific determination whether to implement either: a.) inclusion as part ofits resourceportfolio, in an amount determined by the local board, a BPArenewable product, or other eligible renewable resources, or b.) a greenpricing or green tagprogram for its customers 

### SEC. 4. Covered consumer-·owned utilities to adoptrenewable resource standards 1.) By 2012, each local board for a covered consumer-ownedutility, through a public ormemberprocess, shall adopt and implement a local renewable resource standard givingpriority to thepurposes in Section 1 ofthis Act. 2.) A local renewable resource standard is deemed to meet the intent ofSection 1 ifit targets either:

. a.) 25% ofload with eligible renewable resources by 2025 or b.) 60% ofload growthwith 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 mustbe accompanied with findings and a determinationthatthe standard that is consistent with Section 1 ofthis Act. 4.) The board may adjust the standard ifit determines through_a public or memberprocess and with appropriate findings that there is a lack offirm transmission availability to acquire renewable resources needed to meetthe standard or that the standard cannotbe 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 whichmust be included in any RPS 2.) Nothing in this Act shall cause a consumer-owned utility to reduce its purchases ofthe lowest priced electricity from the Bonneville Power Administration pursuantto Section 5 ofthe Pacific Northwest Electric Power and ConservationAct 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 ofthis Act norto acquire any resource or credits that would cause the utility to have resources or credits in excess of the cumulative electric demand ofits customers. 

### SEC. 6. Annual report to Oregon Department ofEnergy 1.) Each consumer-ownedutility shall submit an annual statementto the Oregon Department ofEnergy thatverifies it is in compliance withthis Act. The statement submitted bythe consumer-ownedutility is for informationalpurposes and is not subject to approval bythe Oregon Department ofEnergy. 

### SEC. 7. Existing rights and authorities ofconsumer-owned utilities 1.) Nothing inthis Act is intendedto limit orrestrict the rights and authority ofa consumer-owned utility, orto subject a consumer-owned utility to the regulatory authority ofthe Public Utility Commission not otherwise providedby law. 

### SEC. 8. Placeholder for statutory changes thatmay be necessary for COUs to implementthe above requirements and policiesUM

__- PGE 2012 RPS Complicance Report Attachment E Page9September 7, 2006
TO: Mike McArthur, Bill Drumheller FROM: RPS Discussion Group DearMike: UM

__- PGE 2012 RPS Complictt?c,e **Jl.e~ort** Attat.hkVnt E Page 10

We are a group ofconsumer advocates, utilities, developers, and enviromnental groups that are members ofthe Renewable EnergyWorking Group (REWG) thatyou chair. As you are aware, we have had many discussions regarding the details ofa Renewable Portfolio Standard (RPS) in Oregon. Our intent with this document is submit to the REWG, for its September 13th meeting inHood River, the following issues for inclusion in the RPS that the Oregon Department ofEnergy 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 notyet consensus. We hope that this informationwill contribute to the discussion on September 13th regarding what the draftRPS should look like. I. ISSUES AGREED UPON A. Defmitions "Load" means the amount ofkilowatt-hours ofelectricitythat a qualifying utility delivered to its Oregon retail customers inthe 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 ofelectricity from a renewable resource, including butnot limited to the facility's fuel type, geographic location, vintage, qualification as an eligible renewable resource, and avoided emissions ofpollutants to the air, soil, or water, and avoided emissions ofcarbon dioxide and other greenhouse gases. "Pacific Northwest" has the same meaning as defmed for the Bonneville Power Administration in section 3 ofthe Pacific Northwest electric powerplanning and conservation act (94 Stat. 2698; 16 U.S.C. 20 Sec. 839a). "Bundled" means when electricity generated from eligible renewable resources is accompaniedby its non-power attributes. Ifa qualifying utility buys both the electricity and the associatedRECs 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. Ifa qualifying utilitybuys only electricity orRECs, but notboth, from a qualifying resource, the power and REC are consideredUM

__- PGE 2012 RPS Complicance Report AttachmentE Page 11
unbundled. Unbundled does notrefer to separating out specific non-power attributes such as avoided emissions ofcarbon dioxide, mercury, nitrous oxide, sulfur dioxide, etc "Renewable energy credit" means a tradable certificate ofproofofat least one megawatt-hour ofan eligible renewable resource where: the certificate includes all ofthe non-power attributes associated with that one megawatt-hour ofelectricity and the certificate is verified by a renewable energy credit tracking system selectedbythe commission. "RenewableResource" There is general agreement that "renewableresource" means an owned or contracted for: (a) solar energy; (b) wind energy; (c) geothermal energy; (d) landfill gas; (e) wave, ocean, or tidalpower; (f) gas from sewage treatment facilities; (g) fuel cells using only eligible renewable resources; (h) biomass energybased on animal waste or solid organic fuels from wood, forest, or field residues, or dedicated energy crops that do not include ( 1) woodpieces thathavebeentreated with chemicalpreservatives such as creosote, pentachlorophenol, or copper-chrome-arsenic; or (2) municipal solid waste. Fossil fuels, nuclear fuels, ortheir derivatives are not eligible renewable resources. "Delivered" and "Delivery" mean the output ofa renewable electricity generation facility that is generated at a location either 1) within the state or 2) out ofstate, but delivered to a qualifying entity's transmission system or contracted point ofreceipt. 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 meetthe standard. UnbundledRECs used for compliance**,.s_a1~ _<_:~~e_** **fro~**
_____ eligible renewable resources located in thePacific Northwest. For RECs from eligible renewable resources outside ofthe Pacific Northwest, both the power and RECs mustbe bundled and delivered to the qualifying entity. Each-renewable energycredit may count onlyonce towards either the requirements ofan Oregonrenewable 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 soldto customers through a retail premium-priced renewable energy tariffshall notbe counted toward compliance with this rule. A qualifying utilityrnay not resell renewable energy credits and countthose sold credits toward the utility's obligation to meet this standard. Cost Recovery An investor-owned utility is entitled to recover inrates all prudentlyincurred costs associated with compliance ofthis standard. A public utility shall also recover its Deleted: Geographic eligibility- the Pacific Northwest</ Formatted: Font: Bold [Deleted:. ( Deleted: shall [ Deleted: mustUM

__- PGE 2012 RPS Complicance Report Attachment E Page 12
reasonable interconnection and transmission costs required to deliverrenewable energy to retail customers in Oregon. ProtectConsumer-Owned Utilities' Access to BPATierI Resources It is agreed that nothing inthis RPS shouldrequire 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 arenewable 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 exactlythe cost cap shouldbe 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 subsequentlymake a case for rate recovery showing that those additional expenditures were prudently incurred. (Some options are presentedbelow)
II. UNRESOLVED ISSUES Below are questions thatremainregarding several critical issues. We hope that these can be discussed atthe REWG meeting on September 13th. Defining Renewable Resource -7 Unresolved issues: Biomass: Questions stillremain about whetherto include (a) black liquor byproduct frompaperproduction and (b) woodybiomass from old growth forests among eligible biomass resources. Hydro: Remaininghydro issues to resolve: (1) low-impact, small hydro- what shouldthe size limitbe and should only smallhydro thatis certified as low-impactbe eligible? (2) Canutilities count onlyincremental improvements at existing hydroelectric facilities that they own or canthey counttheirportionof upgrades at a contractedhydro resource? What about counting RECs from hydro upgrades? Date ofeligible renewable resource Ifthe RPS is to include as a gualitied renewable resource a limited number ofexisting resources it is necessary to determine the cutoffdate for this dete1mination

. ._______________________ ..**--~ ~e_l** 

# 1**~~ed:** It i1 s_ c_nb'11 1 'cal tdofrodecidhe**wh~ch** 1act tties are e tgt e an m ow tar th , . , back. Tite greater the amowtt ofexisting

. Atthe August 15 REWGmeeting, two dates wereproposed: 1) drawmg the lme at facilitiesthatareeligibleunderanRPS, I 1998 to capture the region's first newutility-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 inWY) and 2) going backto 1981 to coincide withthe NW PowerAct. The following is as an illustration ofhow existingresource might impactthe 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 ofall existing large and smallhydro, blackliquor, wood-fired, biogas, wind and geothermal plants in the northwestbackto 1981 equals 1,468 aMW. This means that 67.3% ofthe 25% RPS goal could be metbypurchasing green tags from these preexisting resources . The total amount ofthese same facilities back to 1998 equals 639 aMW, or 30.4% ofthe 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 ofthe congmt ofcost 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 overthe costs ofits 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 ofthe RPS standard have not been **settled~---m•**

....uuum.mmu,........... - u .. - uuuum ....m• Banking ofRECs Severalproposals regarding the vintage ofeligible RECs have been discussed: 1) For any given year the requirements maybe metwithRECs produced during that year, the preceding year, orthe following year. 2) RECs from any eligible renewable resource maybe traded orbanked, but inan effort to encourage early action, a qualifying entitymust surrender the oldestRECs first in subsequent compliance filings (i.e., 'First-in-First-Out'). 3) For any given year the requirements may be met withunbundled RECs produced during that year, the preceding year, orthe following year. Additionally, bundledRECs from anyrenewable resource maybebanked 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 acost cap.UM

__- PGE 2012 RPS Complicance Report Attachment E Page 14

Interim Targets While the 25% by2025 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 onlytwo interim targets that wouldberigid inthat the PUC wouldnotbe allowed to adjust the targets. Another option is to have three or four interimtargets but to allow flexibility so that the PUC could adjust themifneeded. [Troy: should ACP be mentioned here?] Utility Eligibility "QualifyingEntity" Regarding whom is a qualified entitv there are three schools ofthought. First is be all inclusive ofall 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: Whatis the right threshold for determining utility eligibility? PURPA Qualifying Facilities There is a critical questionregarding 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 notallowed PURP A project, this is a conflict andthere is currentlyno wayfor a utility to count a ;::: 1 

# = 0 **p=a=y========~** REC from a QF towardRPS compliance.• **T.~_s**

__**~~()~~~ -~-~** _ **~~~e_s~-~~-~~t~~r -~** **~~_:~zys_**_ot:
_ ....._.---**{~o_e_le_te_d_:**

______ **_____~** in accompanying legislation. One proposal would allow a regulated utilityto have frrst right ofrefusal onpurchasing any RECs from a OF, as long as the avoided cost paid bythe utility is adjusted to reflect the avoided cost the utility wouldhave 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" ofa potential broad-based RPS policywithrelated 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 produceprecise terminology. 

## Fundamental Architecture Key Point All utilities are subject to a renewable energy standard, butthe smallest utilities only need concern themselves with load growth. No public utility will lose its BPA TierI rights. Basis of Compliance with theRPS will be measured in energy units oftotal sales to retail Compliance customers in Megawatt-hours (MWh) Compliance Tradable Renewable Energy Certificates in units ofone (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 ofload served. TierI Power No utility shall be required to lose its rights to Tier I BPA powerthrough 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 oftotal retail electric sales in the State ofOregon (as measuredbypercent of Threshold MWh sales) are subject to the Primary RPS requirements as follows:
End Target 25 percent ofretail load by 2025 and each year thereafter Interim Targets 15 percent of retail load by2015 and each year thereafter until 2020 20 percent ofretail load by2020 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 ofa Secondary RPS as follows: End Target 60 percent ofretail load growth by 2025 and each year thereafter Interim Targets 20percent ofretail load growth by 20 15 and each year thereafter until 2020 40 percent ofretail load growth by 2020 and each yearthereafter until 2025UM

__- 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 ofrenewable resources the list ofresources that qualify for the RPS is onthe generous side, including incremental improvements to existing facilities. Electricity Wind DerivedFrom: Solarphotovoltaic and solarthermal generation Wave, tidal, and ocean thermal Geothermal Biogas from organic sources, wastewater, anaerobic digesters, orlandfills. Biomass as perthe definitions agreed to bythe "RPS Discussion Group", but explicitly including spentpulping liquor Incremental output ofnon-hydro generation units using qualifyingrenewable sources thathave demonstrably increased generation in excess of 10 percent using eligiblerenewableresources through capital investments made afterthe enactment ofthis RPS. Hydropower as defined by SB 1149 The increment ofimprovement resulting from efficiency upgrades to an existing hydropower facility ofany 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 afterthe RPS start date. Theincremental renewable energy proportion ofa multi-fuel generation process. Hydrogen that is reformed from or electrolyzed entirely from the qualifying renewableresources listed above. Qualifying Subjectto the geographic constraints noted below, qualifying facilities are those Facilities using qualifyingrenewable resources that were (1) operational on or after January 1, 1995 and are either {i) located in Oregon or {ii) havebeen serving Oregon load for at least 50% oftheir operational life; or are (2) facilities using qualifying renewable resources thatbecome operational after the enactment date ofthe RPS.
BundledREC Qualifying facilities that generate renewable electricity sold to affected entities with Geographic the associated RECs (bundled RECs) from qualifying renewable resources mustbe Eligibility (a) physicallylocated in Oregon or {b) located outside ofOregon but delivering powerto an affected entity's transmission system or its contracted point ofreceipt.
Unbundled REC RECs thathavebeen unbundled from their associated electricitymust derive from Geographic facilities that are physica1ly located within the Pacific Northwest region as defined Eligibility bythe NorthwestPower Planning and Conservation Act, or those parts ofCalifornia andNevada that fall within the service territory ofaffected entities. Packaged Products Procurement ofbundled RECs as part of "packaged"products (e.g., "shaped" power (e.g., "firmed" or BPA EPP) is permissible but only theproportion ofresources in that "package" resources) that are qualifying renewable resources will count toward compliance with the RPS.
BPAEPP or Ifa BP A decision on the resource mix ofEPP product or its equivalentresults in a Substantially mix that includes resources not listed above a determination maybe made bythe Similar Product Oregon Department ofEnergyto apply an appropriate deflator to the BPA product.

2UM

__- PGE 2012 RPS Complicance Report Attachment E Page 17 

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### DRAFT


## Voluntary Renewable Energy TariffPrograms Key Point All Oregonians shouldbe able to voluntarily purchase renewable energy ifthey so choose, although those purchases should not counttowards the mandatory requirements. Mandatory All utilities and energy service suppliers will berequired to offer a voluntary green Program powerpurchasing programto their customers (similar to Washington statute).
Use ofVoluntary RECs and/or renewable energyprocured by affected entities and used to satisfy Green Energy voluntary customer green pricing tariffprograms 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 TierI PowerExemption "" 

# ~,.,**Ci~ ~~**  

# .t

. '{/

# rr **,.,~{-J** c:"'fft 'lbv'l

. 

## i **~**

# v Key Point ./ 

### '{}!.~ {!!fir (,) 

### 11'1' " 

### There is broad consensus thatthe publics should not lose theirTierI 

### ~r entitlements. li ' / Exemption Scope All utilities thatreceive BPA TierI preference power. r'

RPS Calculation The total load ofan affected entity shouldbe used in determining therequired Modifications portion ofload that mustmeet the RPS for a given target year. However, anypart ofthat load portion that would displace BPA Tier I power shouldbe eliminated from the requirements ofthe RPS for that affected entity on a one-for-one unit basis. Forexample, 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 ofrenewable energy certificates provides necessary flexibility to affected entities in complying withthe RPS. A reasonable cap onthe use ofunbundled RECs is helpful in encouraging long-term policy stability and encouraging development ofnew renewable energy resources inthe 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 inbetween compliance years.

Verification RECs used for compliance must be certified bythe WREGIS orits successor organization, or another tracking mechanism designatedjointlythrough consensus bv the Oregon PUC and the Oregon Department ofEnergy. Unbundled REC Nomore than 20 percent ofan affected entity's compliance in a given compliance Upper Limit year for the Primary RPS Standard can bemetthrough the use ofunbundled RECs, with the excej)tion ofRECs from qualifying customer-sited or off-grid facilities.

3UM

__- PGE 2012 RPS Complicance Report Attachment E Page 18 

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

### DRAFT

RECsfrom Affected entities may satisfYthe requirements ofthe RPS with generation owned Facilities Owned bythe affected entity to the extentthat the RECs generated from that power are by Affected kept and retired bythe affected entity (andthe 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 orwithoutthe associated power, must acquire those RECs under long-term contracts ofat least 15 years in duration. No Double- RECs used for compliance with the Oregon RPS mustbe used solely for the Counting ofRECs Oregon RPS and can notbeused 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 ofthe REC may be stripped out and traded, sold, or otherwise used for any other compliance system or attribute financial market. RECsfrom This issueneeds more investigationbefore language (ifany) 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 ofOregon are eligible for compliance with RPS as long as they Resources meetthe verification procedures and submittal processes set forth by the WREGIS Oj)_erational rules. 

## Resource Diversity Key Point RPS policies do notinherently encourage resource diversity. Ratherthanhaving a "carve out" in the RPS, the public purpose charge will instead be re-focused solely on assisting those resources whichwould otherwise be ata disadvantage under the RPS policy. Set-asides or There are no specific percentage procurement requirements for specificresources "Carve Outs" orresource types within the RPS, premised on substantive changes to the PPC. Renewable Energy Focus the renewable energyportion ofthe Public Purpose Charge (PPC) on Component ofthe funding a mix ofcommunity projects of20MW orless and exclude funding of Public Purpose projects larger than 20 MW. Require as part ofthis statute that the OPUC will Charge ensure thatimplementation ofPPCprograms reflects this change in focus. Community-Level Direct the OPUC, ODOE, ODA, ODF, OECD, and other relevant state agencies to Renewable Energy consider community-basedrenewable energyprojects as critical elements of Goal Oregon's energy policies. Furthermore,these agencies are to support the development oftheseprojects by establishing or modifying procedures and policies as necessary in order to achieve a goal ofhaving at least 8% ofOregon's electrical retail load come from a mix ofcommunityrenewables by 2025.

4UM

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### 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 ofWREGIS certified RECs which are subsequentlyretired in order to Method demonstrate compliance for each affected entity with the RPS.
REC Retirement When complying with the RPS the oldestvintage RECs must be surrendered and retired by an affected entity before newer RECs are used for RPS compliance. Reporting Bodies Forthe IOUs: Oregon Public Utility Commission For the CO Us: OregonDepartment ofEnergy "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 eachbe 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 bythe reporting body as to whether compliancewith 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 meetthe requirements ofthe RPS, with specific renewable energy targets setbythe 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 scrutinizedbythe Adequacy appropriate reporting body and a determination will be made as to whether the Determination report and the acquisition targets within theplan are adequate ornot. Rolling Average Compliance with the RPS will bedetermined using a rolling averagefor each complianceyear. The total ofthe RECs acquired for compliance with the RPS for a given compliance yearwill befigured bytaking the total ofthe yearbefore the compliance year, the total ofthe compliance year, and thetotal ofthe year after the compliance year. Those three years are then averaged for a one-year average. Grace Period RECs for a compliance year must bepurchased and retired within 90 days ofthe end ofthe compliance year for which the RECs are intended to satisfy. 

## Flexibility Mechanisms Banking 

# I Accrual ofRECs generated in a given year, but in excess ofthe target for the given year, can bebanked and held for a period ofup to five years before use. 

# -- Borrowing 

# INo borrowing from future generation is allowed. Onlybanked RECs can be added to the mix computation in lieu ofactuallyprocuring RECs for a given year.

5UM

__- PGE 2012 RPS Complicance Report AttachmentE Page 20 

### DRAFT -Do Not Quote or Cite-- 

### DRAFT September 12,2006 

### DRAFT 

## CostRecovery Key Point Providing a profit incentive is a newer concept with RPS, butis consistentwith 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 energyto 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. ProfitIncentive Utilities may earn an extra profit on their investment in renewable energy ifthese investments provide net economic benefits to customers as'determined by the OPUC, with the bonus limited to twenty-five percent ofthenet economic benefit. (assumed to be substantially similarto 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 ofthe IOU cost cap, with the.possibility offurther discussionbeforebill language is drawn up. Cost Cap Three options have been discussed: Mechanism 1) A limit on the percentage increase in the total revenue requirement ortotal power costs. 2) A resource vs. resource comparison on a case per case basis. 3) An alternative compliance paymentindexed to (for example) twice the average REC price oftheprevious 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 ofpenalties for COUs, and has a good BPAprice referent. Cost Cap An alternative compliance payment (ACP) must be paid ifcompliance with RPS Mechanism requirement through procurement ofRECs is not achieved bythe affected entity.
ACP CostLevel The ACP will be indexed slightly higher than the price ofthe BPArenewable Tier Determination II product or its equivalent to encourage maximizing use ofthe 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 apreference for those pJqi ects serving the affected entity thatpaid the ACP.

6UM

__- PGE 2012 RPS Complicance Report Attachment E Page 21 

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

### DRAFT



## EnforcementMechanisms Key Point Because the IOUs and COUs have different cost cap schemes, the penalty schemes are different as well (withthe COUs using an ACP scheme instead ofpenalties). Non-adequacy Ifa progress report is deemed non-adequate thereportingbody canrequest that Determination another progress report be submitted within 90 days, and this process can continue, until a progress reportthat is deemed adequate is submitted.
Penalties for the Any shortfall in a compliance year as determined bythe OPUC shall result in a IOUs non-recoverable penalty ofatleast (intentionally left blank in the proposed legislation ) amountperMWh ofshortfall. An ACP wouldnot necessarilyrequire aJ.Jenalty amount, although otherpenalties maybe imposed. Penalty Recipient Penalties will bepaid to the NGO sub-contracted to the OPUCto manage public pu:rpose charge funds for thepublic good Penalties for the Penalties are notnecessary for the CO Us because ofthe use ofthe ACP CO Us mechanism. Ifa COUrefuses to paythe ACP the AG should be able to act. 

## Interactions with other Policies

Future Carbon Double counting ofthe 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 ofa REC (retiringthe REC in one system only, but allowing for compliance to bemetin another system) for other accounting systems maybe allowed contingent on the provisions offuture regulatorypolicies. State PURPA Modify Public Purpose Charge Statute ORS 757.612 (4) to requirePGE 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 ofregulatory certainty is needed. Thus, putting in place mechanisms to change the RPS policy is not ideal. Onthe 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 theprogress ofthe RPS and reportbackto the Legislature ifthere areitems thatneed to be addressed through legislation to ensure the continued success ofthe RPS. The taskforce shouldbe able to recommend accelerating goals ifnecessary, but not decreasingthe goals.

7UM

__- PGE 2012 RPS Complicance Report Attachment E Page22 

### October 5, 2006 version- annotated 11/6/2006 

### Oregon RPS andRelated Policy Legislative Package Outline 

### Relating Clause Relating Clause "Relating to Renewable Energy"


### Fundamental Architecture
Basis of 

# lCompliancewiththe renewable portfolio standard (RPS)willbe measured in energy Compliance units oftotal sales to retail customers inMegawatt-hours (MWh) Compliance 

# I Renewable Energy Certificates (RECs) inunits ofone (1) Megawatt-hour (MWh) Mechanism from the Western RenewableEnergy Generation Information System (WREGIS)
Structure 

# J One tier with new and some existing facilities eligible, butwithprimary and secondary RPS requirements dell_ending onpercentage ofload served. FinnFBS Power 

# INo COU shall be **req~ed** to lose its rights to firm Federal Based System power through the RPS. Th1s guarantee does not extendto non-firmpower. Primary RenewablePortfolio Standard (RPS) for Utilities PrimaryRPS All utilities that are responsible for one (1) percent orgreater oftotalretail electric Applicability sales in the State ofOregon (as measuredbypercent ofMWh sales) are subject to Threshold the PrimaryRPS requirements as follows:
EndTarget 25 percent ofretail loadby2025 and each year thereafter InterimTargets 5 percent ofretail load by_2011 and each year thereafteruntil2015 15 percent ofretail load by 2015 and each year thereafteruntil2020

· 20 percent ofretail loadby2020 and each year thereafter unti12025 Secondary Renewable Portfolio Standard (RPS) for Utilities SecondaryRPS Allutilities in Oregon that do not fallunderthe Primary RPS mustmeetthe Policy Threshold requirements. ofa SecondaryRPS as follows:
EndTarget 60 percent ofretail load growth by 2025 and eachyear thereafter Interim Targets 20 percent ofretail load growthby 2015 and each yearthereafter until 2020 40 percent ofretail load growth by 2020 and eachyearthereafteruntil2025 Load Growth Load growth for affected entities willbe measured as the difference inretail load Computation between two five-year averages, one for the base year and one for the compliance year, with eachnormalized for weather conditions. Thefive-year average for the compHance year will consist ofthe compliance year and the four precedingyears. Thebaseyear average will consist ofthe five-year average of2002 through 2006. If the difference in retail load yields no ornegative load growth, then load growth for that period will be considered to be zero for the purposes ofthe RPS.UM - PGE 2012 RPS Complicance Report



### October 5, 2006 version- annotated 11/6/2006 Primary RPS Opt- Any utility may optin to the Primary RPS ifthey so choose, butmust stay with the in Primary RPS for a minimum offive years once they have opted for the standard, regardless ofwhether they remain or fall below the threshold. "Drift" into Any entity that grows suchthatit falls or "drifts" into the PrimaryRPS after the RPS Primary Standard enactment date mustmeetthePrimaryRPS on the same timeline as iftheyhadbeen under the standard atthe enactment date ofthe RPS. Renewable Portfolio Standard for Electricity Service Suppliers (ESSs) ESS RPS TheRPS requirement for ESSs serving Oregon load consists ofan amount ofload Obligation equal to the aggregate total ofobligations thatwould exist as ifeach customer servedbytheESS were insteadbeing served by its applicable utility based on the service territory inwhich the customer or service location is situated.
locc D



### Qualifying Renewable Resources Electricity Wind DerivedFrom: Solarphotovoltaic and solar thermal generation Wave, tidal, and ocean thermal Geothermal Biogas from organic sources, wastewater, anaerobic digesters, or landfills. Biomass, andbyproducts from thatbiomass, based on (I) organic human or animal waste; or (2) solid organic fuels from wood, forest, orfield residues; or (3) dedicated energy crops. Spentpulping liquor is considered an eligible byproduct for purposes ofcompliance with this RPS. None ofthe above products may include (!)wood pieces that have beentreated with chemical preservatives such as creosote, pentachlorophenol, or ccp_per-chrome-arsenic or (2) municipal solidwaste. Attachment E Page 23

.

**C~mment** [BDl]i : **'Remo~ed** by general:: · ·agreerileritatbst

.···.·.·. ·· 

### meeting

..· .. /.·.··.· ··••··

Incremental outputofnon-h;ydro generation units using qualif)dngrenewable sources thathave**~~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 ofSB 1149. The increment ofimprovementresulting from efficiency upgrades to an existing hydropower facility. Efficiencyupgrade projects on BP A facilities qualifY, but only the amount proportional to Oregon's allotted share (as measuredby the aggregated loadofOregon's consumer-owned utility BPA customers) oftheFBS for the COI11Pliance_yearmaybe utilizedby affected entities for compliance with the RPS. The incremental renewable energyproportion ofa 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 shouldbemade Qualifying eligible for the RPS is left to the periodic taskforce convenedby the Governor (see Resources end ofoutline). Underno circumstances can electricity derived from fossil fuel resources, nuclear, or the combustion ofmunicipal solid waste qualify for the RPS.

2Date ofEligibility

BundledREC Geographic Eligibility

UnbundledREC 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 Subjectto the geographic constraints notedbelow, eligible facilities are those using qualifying renewable resources **thati\Y¢r~_9]2eratj<?_n_al** on or af!.e! Jl!nJl!ll)')_,J995.

----- AbundledREC shallbe considered to be created at the point when the, (1) electricity generated from afacility physically locatedwithin the WECC NERC region using a qualifying renewable resource is delivered to any affected entity's transmission system, the transmission system ofthe Bonneville Power Administration, or the transmission system ofany member ofthe NorthwestPower Pool**kWI.fr~·MfulJ:~~~~i~i:t:! £<?.IItl?.ip.~tioy_~i~** (22**!~e)~~Q~ ~-e9i.fJE~l)y_** **~s~<?_cj~t~c!_**

___ -- withthat generation. To beused for compliance withthe RPS the **powe~** bundled with the REC mustbeprocured **~: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:ittusing 

# :;:~~~Ji; 

# ' .•. the affected entityfor transmission to a designatedpoint ofdelivery identified by the ' affected entity or their scheduling agent. However, the electricalpower component '--I comment [sos]: Misuse oftenninology onmy part. ofthatbundled REC may**l:J~ ~1lbstitut~d.** forpy any combination ofequivalent system Or other power**~R**

## areai 

## tiihe

## qt**de~~yed**basis **~~~e~Jli.J.!.C~}!t_iq_n_ qfj:];!~** 

______ bundledREC based on the above definition andultimate delivery ofthe power with

- Comment [BD6]: its associated REC to its final destination for distribution bythe affected entity. Concern aboutusing **"Teal.thne,~­** temnnology RECs that have beenunbundledfrom 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\dproposed

. so/5o G;imprtn:Oise)

.. •·•·· Pacific NorthwestElectric PowerPlanning and Conservation Act, or those parts of California andNevadathat fall within the service territory ofaffected entities. Procurement ofbundled RECs as part ofacombinedrenewable and non-renewable contractual energy products (e.g., "shaped" or "firmed" powerproducts) is permissible but only the proportion ofresources in that combination ofcontracted energy resources that are qualifying renewable resources- as determined upon inception ofthe 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, erthe eembustion ofHHmieipal solid •.vaste aad (ii) atleast 90 percent ofthe power assoeiatedwith that IJroduct, based on the
· composire yearly average portfelio ofthe BP:A, EPP package offered to a!! ofBPA's customers, oaa be attributed to generation from qualifyingreE:e\vable resourees identified in this RP£ policy. Iffor any reasoll: the BPA EPP product or substantially similarproduet 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 ofEnergy 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 TariffPrograms Mandatory Program
Use ofVoluntary Green Energy Purchases in RPS All utilities will be required to offer avoluntary green powerpurchasing program to their customers. Beyond some basic parameters (similar to Washington statute), program implementation details are at the discretion ofthe 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.

3UM - 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 ofFederal Base System (FBS) powerfrom the Bonneville PowerAdministration (BPA). Firm FBS Power No consumer-owned utility shall be required to lose its guaranteedpreference power Exemption allocation offirm FederalBase System (FBS) power. This guarantee does not extendto non-firm power. RPS Calculation The total load ofan affected entity determines therequired portion of!oad that must Modifications satisfY RPS resource requirements for a given year. ThatRPS obligation maybe reduced, however, ifanypartofthat load portion would unavoidably displace firm FBS powerpreferentially allocated to the affected entity. This partial (orfull in some cases) exemptionfrom theRPS requirement is limited to an amount equal to the amount offirm FBS powerthat would have unavoidably been displaced ifthe full requirements ofthe RPS were to be applied to the affected entity. 

### Mid-Columbia Hydropower Obligation Deferment Applicability Consumer-ownedutilities with historic low-costpowercontracts for Mid-Columbia powerfrom Mid-Columbiadams ownedby Washington public utility districts. Obligation After accountingfor any displacement offirm FBS power, any consumer-owned Deferment utility thatwould face a further displacement ofpower derived from an active historical low-cost, long-termpowercontract with a Mid-Columbiahydropower facility may, for that complianceyear, reduce their RPS obligation by the equivalent amount ofthepower delivered thatyearthrough that historical low-cost long-term powercontract. When the historical low-cost, long-tenn contract expires the consumer-owned utility is not allowed to defer this part oftheir obligation any longer and mustprocure the appropriate resources to meetthis portion oftheirRPS obligation. However, ifthe 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 ofthisportion ofthe affected entity's obligation may continue through the next contractperiod. 

### Renewable Energy Certificates
Verification

Long-term Contracting Standard

UnbundledREC Upper Limit for Primary Standard RECs used for compliance mustbe certified by the WREGIS orits successor organization, orifnecessary, another trackingmechanism designatedjointly through consensus bythe Oregon PUC and the Oregon Department ofEnergy.
lr ' ' '· .,).,".· "-······

.. D **:4~** +1-

..

...... '.t;

...... · ..... ·''

......, · .... ·

...·.· .......,.:'(,

..,,·;,,,··.. . ,71.',J.:.:

.. ··:· .. **·~·**.. · . ".J **~~ ~**  **req~irO!fi~S,~S(~oq~** 

### atJeest}5 percent **efllie~eFfoCs** \lnder loagteim 

### SQ!ltiacis of

### atliias(io **)'ear~** iB 

### d'!iiac:t'imt. The;eis nel'centraet$g stas:dard ferthe "··"·'·'':.' **;,;··.··;·riri0~':',:,**..:..,..,...,,: iii
.... ':·''...:··

..... '.:···:;.·.,,

...,...·.::'· :t..,
......,..... ,···n'ill'10. · .···::.. '·

.....··. ·.: ... : **~"** ,D<'<'. ·I 

### ' No more than 20percent (or a higherlimit as determinedbyPURPA QFpurchases) ofan affected entity's annual compliance for the PrimaryRPS can bemetthrough theuse ofunbtmdled RECs. UnbundledRECs from qualifYing customer-sited or offgrid facilities are exemptfrom this upper limit.

4 - Comment [BDlOJ: Contracting standard to be dropped, May 

### .need some authority forPUC tostep in ific probiemdo\VJ1. **th~linei**UnbundledREC Upper Limit for Secondary Standard RECs from PURPAQF's

.. RECsftom OwnedFacilities

RECs from Public Purpose Charge FundedProjects 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 determinedby PURPA QF purchases) ofan affected entity's annual compliance for the Secondary RPS can bemetthrough the use ofunbundledRECs. UnbundledRECs from qualifying customer-sitedoroffgrid facilities are exemptfrom thisupperlimit. 'Ifan affected entity purchases a bundledREC from a PURPA "Qualifying Facility" (QF) that delivers power on a real-time basis to Oregon than the computedupper limitfor that complianceyear onunbundledRECs for thataffected entity is raised by oneREC's worth ofpower (1 MWh), withthe upper limit onunbundledRECs increasing cumulatively for eachbundledREC purchased from a PURP A QF

. Affected entities may satisfy the requirements ofthe RPS withgeneration ownedby the affected entity to the extent thatthe RECs generatedfrom thatpower are kept andretiredbythe affectedentity (and the RECs mustbeWREGIS 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**

## 8iJ3j,¥i_jeetil 

### ifi:e **~seats**

### a.!_

_______ Fora multi-state investor-ownedutility, the share ofbundled_RECs (associated with an owned project or a power purchase) allocated to Oregon should, at a minimum, include all RECs associatedwith the above-market costs paidby Oregon ratepayers for thepower orproject and a fair allocation ofRECs for marketcostpurchases (or **cheape~)** as determinedthrough the OPUC and its proceedings. · RECs retired for compliance withthe OregonRPS mustbe counted towardthe OregonRPS andcannotbeusedfor compliance with any other state's RPS. RECs used for compliancewith the RPS must include all environmental attributes associatedwiththat REC from its inception. No environmental, emissions, or other attribute oftheREC mayberemoved and traded, sold, or otherwise retired for use with any other compliance system orattribute financial market. RECs from customer-sited and off-grid qualifying renewable resources located within Oregon are eligiblefor compliance as long as t)ley meetthe 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 specificpercentageprocurementrequirements for specific resources or "Carve Outs" resource types within theRPS, premised on substantive changes to the PPC.
Renewable Energy Focus the renewable energy portion ofthe Public Purpose Charge (PPC) on funding Component ofthe a mix ofprojects of20 MtN or less and exclude funding ofprojects larger than 20 Public Purpose MtN. Require as part ofthis statute that the OPUC will ensure that implementation Charge ofpublic purpose charge programs reflects this change in focus. Community-Level Community-basedrenewable energy projects are an essential element ofOregon's Renewable Energy energypolicy, and itis a goal ofthe State ofOregon that atleast 8percent of Goal Oregon's electrical retail load comes from a mix ofsmall-scale renewable energy projects ofby 2025. To the extent feasible, all state agencies shouldmodify or establish relevant policies andprocedures to helpthe state achieve this _goal.

5UM - PGE 2012 RPS Complicance Report



### October 5, 2006 version- annotated 11/6/2006 Attachment E Page 27



### Compliance Procedures Compliance Path Retirement ofWREGIS certifiedRECs byrequest ofaffected enti*s Compliance Year Every calendaryear from the effective date ofthe RPS onwards will be considered a for **Pr~mary** and compliance year for the Primary standardfor which RECs mustberetired atthe ESS Standard request ofthe affected entity in order to, depending on the year in question, either meet a specified target orto maintain a minimum level ofcompliance with the RPS. Compliance Year Every calendaryear from the first interimtarget onwards will be considered a for Secondary compliance year for the Secondary standardfor which RECs mustberetired at the Standard request ofthe affected entity in order to maintain a minimum level ofcompliance with the RPS as determinedby the load growth methodology and applicable targets. Compliance with Each interim targetrepresents a plateau for which each affected entity must satisf'y "Hard" Targets for theRPS byretiring, ata minimum, the appropriate number ofRECs to meet the Primary Standard targetfor the first year the interim target takes effect and to continue meeting this target each yearthereafter untilthenext interim target takes effect. This process continues until the endtarget is reached, atwhich pointaffected entities must continue to retire at leastenoughRECs to meet the end target inboth the yearthe end targettakes effect and each year thereafteradinfinitum. 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 reportingbodyproviding specific Primary Standard plans to meetthe requirements oftheRPS, with specific annual renewable energy targets setbythe affected entity for each yearbetween and before the interim targets. Foryears between interim targets, andbetween the last interim target and the end target, these targets must be designated at a level above the minimumlevel set bythe priorinterim target. The PUC mayestablish appropriate procedures for investor-owned utilities to align this reportingprocess to the lRP process to the greatest degreepossible so as to minimize the administrative burden created bythis reporting process. Compliance with Each affected entity mustprocure enoughRECs to meetorexceed the proportion of Secondary load as determined by applying the load growth determination methodology and the Standard interim target thatis ineffect for that compliance year. Failure to procure a sufficient quantity ofRECs to meetthe RPS will result inpenalties being applied. Compliance with Each affected entity mustprocure enough RECs to meetor exceed theproportion of ESS Standard load as determined bythe 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 ofthe end ofeach complianceyear, Compliance submit a letter to the appropriate reporting bodyreporting the quantity ofRECs Update Letter retired thatyear for purposes ofcompliance with theRPS. Ifthe affected entity failed to meet the designated target or otherwise applicable loadquantity forthat year an explanation for that failure must beprovidedin thebody ofthe letter. Time of A compliance determination with the RPS for each affected entity will be made by Compliance the appropriate reporting body 1to 3 month after submittal ofthe 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 oftherolling average computation methodology in thepenalty determination phase.

6Rolling Average Penalty Test for "Hard" Targets in Primary Standard

Annual Minimum Compliance Determinationfor Primary Standard
Reporting Bodies UM

__ - PGE 2012 RPS Complicance Report Attachment E Page28 

### October 5, 2006 version- annotated 11/6/2006

Forthe purposes ofdetermining penalties in the Primary standard, an additional compliance testwith the RPS targets will be applied for the first year ofeach 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 campHance year in this situationwillbe figured bytaking the total ofthe year before the compliance year, the total ofthe year after the compliance year, andthe total ofthe complianceyear. Thosethree years are then averaged for a one-year average to determine compliance in terms ofpenalty application for those years in which an interim or endtargetbegins. In cases whereinsufficient RECs have been procured to meetthe interim or end targets as computed penalties will be applied. Foryears between interim targets inthe Primary standard, andbetweenthe last interimtarget andthe end target, the annual compliance updateletter submittedby each affected entity will be checked to ensure that at least enough RECs were retired that year to surpass the minimum floor establishedby theprior interim target. Ifnot enoughRECs were retired by the affected entity to, at a minimum, surpass the minimumfloor for that yearpenalties willbe assessed accordingly. For investor-ownedutilities and ESSs: Oregon Public Utility Commission For consumer-ownedutilities: OregonDepartment ofEnergy 

### Flexibility Mechanisms
Grace or "Truing RECs for a complianceyear maybepurchased andretiredup to 90 days after the Up" Period end ofthe complianceyear for which the RECs are intended to satisfy.
BundledREC BundledRECs procured from parties other than the affected entity can be held and Banking from used by the affected entity for a period oftime equal to Y. ofthe contractperiodby Market Purchases which the RECs are procured. (e.g., a 10-year contract would equalS years) Banking ofRECs BundledRECs generatedby facilities ownedby an affectedentity and retired by the from Owned same affected entity for the sake ofRPS compliance may beheld and used for a Sources period ofup to 10 years.
RECsfrom Unbundled RECs maynotbe held (banked) andusedinfuture complianceperiods. Unbundled RECs They mustbepurchased and used within either the complianceperiod or the grace periodprovidedfor in this policY. Borrowing No borrowing from future generation is allowed. Only bankedRECs can be added to the mix computation in lieu ofactually procuring RECs for a given year. 

### Cost Recovery Recovery All prudently incurred costs associated withRPS compliance are recoverable, Standard (for includingthose associated with transmission and delivery ofrenewable 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 markettransformation activities for early-stage for Early-Stage renewable energy development (e.g., permittingregardingwave energy) are not Market Activity discouraged orpenalized bythe RPS or costrecovery aspects ofrelated policy.

7UM - 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 ofthe RPS, andthat costcap will have as Mechanism its basis the electric-onlyportion ofan affected entities total revenue requirement.
Cost Cap The cost cap will be computed using an above market costtest atthe time ofthe Procedures resource decision, with the test applied to the total delivered cost ofthe resource using a fair basis ofcomparison incorporating current 1RP procedures and methodologies

..(More details involvedwith 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 ofat least $45 perMWh ofshortfall. Penalty Recipient Penalties from IOUs will be paid to the NGO sub-contracted to the OPUC to manage public purpose charge funds for thepublic good. Penalties from COUs will bepaidto a similar entity (to be determinedthrough rulemakingbythe ODOE) for renewable energy projects in consumer-ownedutility territory orterritories. 

### Interactions with other Policies
Future Carbon Double counting ofthe greenhouse gas emission attributes from a REC for any Regulatory future greenhouse gas cap is not allowed (i.e., retiring a REC in two ormore Policies different systems). Double use ofa REC (retiring the REC in one system only; but allowing for compliance to be met in another system) maybe allowed contingent on the provisions offuture regulatory policies. People's Utility Placeholderfor a number ofchanges to existing statute thatmay berequired for Districts Legal PUDs to implement some or all portions oftheRPS. Placeholder for additional Modifications modifications for othertypes ofCOUs thatmay be necessary as well.
Public Purpose Extendthe public purpose charge (PPC) through 2025 to be consistent with and Charge serve as a complementto theRPS policy for smaller, community-level resources. StatePURPA ModifY Public Purpose Charge Statute ORS 757.612 (4) to require PGE andPacific Power to meet state PURP A Statute ORS 758.505 to 758.555. 

### Changes to the RPS
Periodic Task Force A taskforce will be convenedbythe Governor 12 to 18 months after each ofthe interim targetyears to evaluate the progress ofthe RPS andreport backto the Legislature ifthere are items thatneed to be addressed through legislation (e.g., additional qualifYing resources)_to ensure the continued success ofthe RPS.

8 Attachment E Page 29UM

__- PGE 2012 RPS Complicance Report Attachment E · Page 30 

### 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

1UM - PGE 2012 RPS Complicance Report Attachment E Page 31


### 1 field, protect clean air and water, and position Washington state as a 2 

### national leader in clean energy technologies.
3 4 

### 5 6 7 8 9 

### 10. 11 12 13 

### 14 

### 15 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 2UM

__- PGE 2012 RPS Complicance Report Attachment E Page32


### 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
3

### 1 2 3 4 5 6 7 8 9 10 11 

### 12

/' 

### 13 

### 14
15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 UM - PGE 2012 RPS Complicance Report Attachment E Page 33



### 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 thirty4UM

__- PGE 2012 RPS Complicance Report Attachment E Page34


### 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

5UM

__- PGE 2012 RPS Complicance Report Attachment·E Page35



### 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.

6UM

__- PGE 2012 RPS Complicance Report Attachment E Page36 

### 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 utility

### 6 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 22 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 7UM - PGE 2012 RPS Complicance Report Attachment E Page37



### 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 qualifyingutility 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 8

### 1 2 3 4 

### 5 6 7 

### 8 

### 9 

### 10 11 

### 12 13 

### 14 

### 15 

### 16
17 

### 18 19 

### 20 21 

### 22 23 24 

### 25 

### 26 27 28 

### 29 30 

### 31 32 33 34 35 

### 36 37 UM

__ - PGE2012RPS Complicance Report Attachment E Page 38 

### 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. UM - PGE 2012 RPS Complicance Report Attachment E Page39



### 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

---



### ...

10UM

__- PGE 2012 RPS Complicance Report Attachment-E 

### RPS 2010Advisory 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 ofOregon (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 ofthe RPS rulemaking advisory .committee to order at 1:05 pm. The meeting was held atthe Oregon Department of Energy (ODOE). b. The committee discussed the meeting minutes from the August 101h 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 ifthe 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 101h 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 40UM

__ .- PGE 2012 RPS Complicance Report Attachment E Page 41 · 

### RPS 2010Advisory 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 oftown and so itwould 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 justfor 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 ofCommerce 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. Option2- the straw proposal- is to modify the RPS administrative·rules to provide an alternative to WREGIS forthe start-up phase. Megan Decker sought to clarify the end date ofthis 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 staffis aware that this is under discussion but, ifthe 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 ofwhether 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 ofwhether the utilities planned to 2UM

__- 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 of2007 thatthey are looking to secure. Megan Walseth-Decker asked for added clarification about the 3/31/2012 date, whattime period the interim system is intended to cover and what time period is for the stranded generation. She also asked ifthe drafters anticipated an end-datefor 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 thatthe 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 thatin orderfor 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 yetto be.converted to a WREGIS REC. Also, ODOE would want to clarify the issue with WREGIS. He noted thatthere are also independent players who may be unaware ofthis issue. Kip said thatthe group may wantto consider an end-date. He noted that atthis point, if afacility 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 ofthat c;late is to treat it as the last eligible vintage ofgeneration.

. v. Megan Walseth-Decker asked ifthat was what the parties who proposed the language intended. vi. Brendan McCarthy said thatfor the first halfof2007, PGE sold their RECs with a signed attestation, vyhich was sufficient for the voluntary REC-based programs. He stated thatthis 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 offlexibility balanced with putting a system in place by the end ofthe year. He confirmed thatthis alternate system would be confined to specifically addressing the backJog issue. He noted thatWREGIS does not yet **accoun~** 

### for output due to hydropower upgrades. vii. Kip Pheil noted thatthere 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 thatthe proposed language uses the term "qualifying electricity" for a reason. It is not intended to change what type ofelectricity qualifies, butjustto facilitate the WREGIS system. ix. E'A'EB <;larified that the intent---e-f-3131/2012 date is to be the date that afacility must be registered with WREGIS by. d; Doris Penwell asked whether the process for registering afacility with WREGIS requires the owner to first register with ODOE. Kip Pheil answered that owners usually contact him atthe 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 3UM - PGE 2012 RPS Complicance Report 

### RPS 2010Advisory Committee Meeting 

### Meeting #3 Minutes

1:00pm 

### to 3:30pm 

### Oregon Department of Energy Attachment E Page43



### 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 ofhow to allocate electricity due to the upgrade. Kip expects thatthe end of2'008 would be long enough. ' e. Kip Pheil believes thatthere 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 thatthis 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 stakeholdergroup 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 priorto rulemaking. Brendan McCarthy answered.thatthis has been a problem for a long time and that they were hoping thatWREGIS would accommodate them. h. Sandra Walden asked about the costs associated for registering with WREGIS and commented on the importance ofkeeping the costs low. Andrea Jackson answered that WREGIS registration costs depend on the total generator capacity ofeach account. She believes thatthat maximum is $1500 peryearto maintain an account and thatthere 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 thatWREGIS costs are very minimal with the exception that for a very small system, the minimum annual cost ofabout $200 peryear can be relatively large compared to the REC value. Tom O'Connor said thatfor him, these costs are a big issue and that BPA has established sub-accounts to handle REC banking for small utilities butthejury 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 thatthe proposal is an alternative for some ofthe output. j. 

### Kip Pheil introduced a third option. The companythat has built all ofthe tracking systems, including WREGIS, has also developed the North American Renewables Registry (NARR). NARR does not have 

### the same kind ofconstraints 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 

## autility alongside WREGIS reports. Kip will look into this more.The group needs to look irito the othertwo options as well and then revisit the discussion. i. Brendan McCarthy commented on Kip's summary. He pointed out thatthe statutory language does not referto 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 thatthe statute requires consultation with the PUC and asked ifODOE had made any initial consultations. Kip Pheil replied thathe had talked with PUC staff but on a broad scale. None ofthe utilities have talked with 4UM

__- PGE 2012 RPS Complicance Report Attachment E 

### RPS 2010Advisory Committee Meeting 

### Meeting #3 Minutes

1:00pm to 3:30pm Oreg_on Department of Energy Page 44

the PUC staff aboutthis. Kip Pheil told the group that he is hoping to have a PUC person atthe 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 ofgeneration for multi-fuel facilities. In terms ofeligible upgrades, ORS · 469.020(2) refersto "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 thatthis is similarto some other RPS programs use of a "repowering" provision. ODOE will draft language on this subject for the next meeting. There is an argumentthat 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 thatthe term "re-built" also seems like thatwould be extending a facility's life. Kip Pheil responded thatthere might be an argumentfor treating a facility like a new one. He also said that it may be best to try a align with California's RPS program exceptthat there may be times when we.would not wantto require the replacement ofthe prime mover as California does. We should work through some ofthose scenarios. c. Jeff Bissonnette commented that ifinvestment is made in a facility that increases efficiency, at some pointthere 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 ifthere were reasons notto use the same standard as California. Kip Pheil responded thatthere are a variety ofreasons 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 otherstates have done but Oregon may not wantto follow other states' paths in this situation. He suggested looking at otherOregon statutes that have the phrase "becomes operational" in orderto determine its meaning. He specifically mentioned that some of the "right to farm" laws use that phrase. In Air Quality statutes, itis 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 thatthe group considerthe purposes ofthe 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 thatwould help Oregon move forward. He used the Boardman plant as an example ofan 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 5UM

__- PGE 2012 RPS Complicance Report Attachment E Page 45 

## RPS 2010Advisory 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 newfacility 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 meetthe percentage ofinvestment for repowering. iii. Megan Walseth-Decker asked whetherthe 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 ofthe answer. Lisa Brown commented that Oregon has nottaken 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 itselfin 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 hydropowerfacility 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 thatthe 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 whatqualified 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 ofa hydropower facility designed 50 to 70 years.ago and may no longer operate underthe original flow patterns. Lisa Brown ofWater Watch commented on one ofthe key pieces for differentiatin·g between the two terms -the principal that power is being generated based on the same amount ofwater. Rick Oliver commented that it sounds like an efficiency upgrade is power in divided by powerout. Group members questioned **wh~ther** capacitywould be based on nameplate capacity. Kip Pheil acknowledged that this is something thatthe rules would have to be very clear about. c. Jeff Bissonnette commented that many ofthese questions stem from the original bill. He asked whetherthere had previously been rulemaking on these subjects. Kip Pheil answered thatthe 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 6UM

__- PGE 2012 RPS Complicance Report Attachment E 

### RPS 2010AdvisoryCommittee Meeting Page 46 

### Meeting #3 Minutes

1:00pm to 3:30pm Oregon Department of Energy said thatthe capacity v. efficiency issue has become particularly relevant now because BPA is starting to make some ofthese upgrades. d. Kip Pheil said thatflow optimization would prove the most difficult ofthe three categories ifthe committee decides to take it on. The **coll!m~ttee** 

### would have to determine what the "same amount ofwater' actually means. He continued that this is potentially burdensome because ofthe cause and effect issue. Lisa Brown responded thatthere 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 cleanerto say no credit for increasing flow. He also said thatthis point is something for the group to think about priorto 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 ofaccomplishing this. He has been working on this with Bonneville 1S 

### Deb Malin. He is not sure ifthis needs to be addressed through rulemaking. 6. The committee discussed other issues a. Ryan Flynn asked aboutthe status ofthe bundled REC issue. Kip Pheil noted thatthe initial set ofRPS rules that ODOE filed relied on use ofthe 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 thatwhen a utility takes energy directly into its system, there is no transfer ofpower 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." Ifthe interconnected utility is the same as the utility which retires the REC this is alternate proofof a bundled REC. Kip noted thatWREGIS is revisiting the e-tag procedure to address a wider range ofmarket 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 ofthe meeting to allow remote staffto follow the discussion more easily. b. Lisa Brown asked how the public can review applications for the RPS. Kip Pheil answered thatthe WREGIS website will show facilities thathave 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 ofwhat 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% 

### ofits 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 ofthe first [2011) 

### compliance period. 7. The committee planned the next meeting

7UM - PGE 2012 RPS Complicance Report Attachment E Page 47 

### RPS 2010Advisory Committee Meeting 

### Meeting #3 Minutes

1:00pm to 3:30pm Oregon Department of Energy The next advisory committee meeting is planneg 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.

8UM

__- PGE 2012 RPS Complicance Report Attachment E 

### RPS 2010Advisory 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 MeganDecker, RNP Ryan Flynn, PacifiCorp BrendanMcCarthy, PGE Kate Miller, Trout Unlimited GlennMontgomery, OSEIA Tom O'Connor, OMEUA
· Rick Oliver, Central Lincoln

PUD/OPUDA. Doris Penwell, AOC, CREA ZaybnTowner, PNGC Paul Woodin, CREA Members Absent: Ellie Booth, Covanta Energy Lisa Brown, WaterWatch ofOregon (alt.) ·
1. fntroductions andAgenda Overview Gary Marcus, Falls CreekHydro Glenn Montgomery, OSEIA SandraWalden, OSEIA 

### (alt.) ODOE StaffPresent: 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 LynnAverbeck, ODOT Solar Highway Program Christie Sharpe, PacifiCorp

. Nicole Merendino, SunEdison

1. 

### The Committee noted·thattheminutes from the September 9th 

### meetinghavenot beenposted onthe 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 Pheilreviewedthe WREGIS data entryprocess, 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 inWREGIS. Tom O'Connor asked ifan applicant would need to have a particular state orvoluntary program inmindwhen applyingto WREGIS. Kip answeredthat is unlikely that WREGIS would require an applicant to prove thatits generation would meetthe requirements ofa particular 

### state orprogram beforeregistering it 

### He clarified 

### thatDDtJ..OuE;:,.._

_____ _ does not officially beginprocessing a facility until ithas beenregistered with WREGIS. Once a generator is in WREGIS andhas the certifications from programs that itwants, thenthat generation date (MWh/month) is put

1UM - PGE 2012 RPS Complican<;e Report 

### RPS2010AdvisoryCommittee Meeting Meeting #4 Minutes

9:00am to 3:30pm Oregon Dept. ofTransportation, Portland, OR Attachment E Page49



### into WREGIS by a thirdparty (either the utility or portiori ofthe utility taking the electricity). b. Juliet Johnson asked about ifthe qualifyingreporting entity is responsible for reporting the actual number ofmegawatt hours to WREGIS and· whetherthe qualifyingreporting entity (QRE) is also responsible for registering the generator with WREGIS. Kip explained that the generator's owner is responsible for registeringthe generator with the WREGIS system and that the QREs are more like accountholders thatthe generators can signup with. Teri Ikeda ofPacifiCorp confirmedthis. Teri Ikedafrom PacifiCorp respondedto the question. c. Kip showed a sample REC andhighlighted where onthe certificate to find certain information. Tom O'Connor asked where information about the QREs would be listed onthe REC. Kip pointedto the line listingthe reporting entity or organization. d. Question ofwhether a facility with multiple qualifying fuel sources would needto have multiple QREs? Kip said that electricity that is generated from different sources would need to be accounted for separately- that is theheart ofthe multi-fuels issue. There is generallyjustone reporting meter for a facility. Kip explained that WREGIS allows for generator. owners to separate output based on different sources. Output does nothave to go to the QRE through multiple meters for itto be separated in WREGIS. e. Kip explainedthat once ODOE is,sues a certificationID 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 canproduce as many certificates as it wants or is capable of Once the certificationID is issued, ODOE does notknowhowmany RECs a facility produces -thatis proprietary informationwithin the WREGIS system. ODOE is expected to test withwhetherthe generator meets the rules, uses the right resources, uses the rightprocesses to generate electricity. f. A generator should be able to earn one REC for everymegawatthour of qualifying electricityproduced. It should be equitable between generating owners. There should beno disadvantage to having a single ormulti-fuel facility. 2. Kip spoke about the need to balance the precision ofcompliance 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 ofthe utilities' compliance status with the RPS and where that information would be located. Kip answered that the PUC tracks the information for IOUs. Theutilities file implementationplans every-other year and file updates to thoseplans

2UM _- PGE 2012_RPS Complicance Report Attachment E 

### RPS 2010 Advisory Committee Meeting 

### Meeting #4 Minutes Page 50



### 9:00am 

### to 3:30pm 

### Oregon Dept. ofTransportation, Portland, OR every year in-between. They must file a compliance report inMarch 2012 for the 2012 compliance year. i. Juliet Johnson asked ifthere is someplace inWREGIS that says if a REC has beenused to complywiththe Oregon RPS and is therefore retired. Kip responded that information is what is turned inwith compliance reports. 

### Inthe 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 ownreport. 3. P-rohibited Sources
·**~~•·.**

### a. Kip quoted·the statute; whichstates that ODOE maynot approve **:~,,** 

### petroleum, natural gas, coal or nuclear fission as an energy **source~** 

### Kip 

### also pointed outthat wood treated with certain chemical preservatives are '· · not eligibly for the RPS under statute.

b. Tom O'Connor asked whether WREGIS maintains a summarylistofwhat sources each states consider eligible sources. Kip answered WREGIS has not attempted to provide thatkind ofmarketinformation for participation, but itwould rely on some other entity. Another source is the LawrenceBerkeley Lab. 4. Source v. Process a. 

### In2010, new sources were made eligible because oflegislative action. These sources include somepre-1995 hydroelectricprojects, some pre1995 biomass facilities. Also in2010, a newprocess was made eligiblethe combustion ofmunicipal solid waste (MSW). b. Combustion oftreated wood and nuclear fission are still prohibited processes inthe Oregon RPS. 5. Multi-Fuel Examples a. Biomass combustion such as hog fuel, or saw dust. These types of facilities generallyneed to have natural gas onhand to keep the facility gorng. b. Concentrating solar power. There are none ofthese yet in Oregon. One thought is to backup solar power with natural gas. c. MSW energyrecovery.. There is typically some type ofnatural gas co-fire. There is a lot ofpetroleum-derived waste inthe feedstock. d. There are somepotential sources thatmay not clearly be eligible or ineligible for the Oregon RPS. 6. ConversionEfficiency a. Simple efficiency calculation is energy out over energy in. b. Key factors to efficiency, such as the energy density ofthe fuel source. Also, moisture content- howmaterials are burned. Also, howthe machine has been built and howitworks is important.

3UM

- PGE 2012 RPS Complicance Report 

### RPS2010Advisory Committee Meeting 

## Meeting #4 Minutes

9:00am 

## to 3:30pm 

## Oregon Dept. ofTransportation, Portland, OR Attachment E Page 51



### c. Needto find a way to effectively capture these variables in order to determine a consistent efficiency standard. Kip suggests looking at a fairly discreet timeperiod. He generally looks at the hourly values ofa facility · and sumup the results ofthat over a month. There maybe smaller facilities where it might be feasible to simplylook at monthly averages. 7. Multi-Fuel Review a. 

### Kip tells the group that ODOE will try

### to develop 

### draft language and release itto the committee before the next meeting. b. Question ofhowproprietary data would be protected with ODOE requiring certain datato determine efficiency. There are ways .to address confidentially concerns. However, what is needed is some general way that ODOE will approachthese projects, eventhoughprobably every project will beunique. c. JeffBissonnette commented that the multi-fuel discussion for MSW is pretty limited, based onthe statute. Are you goingto consider whatis in the feedstock ofanMSWfacility? 

### Kip answered that there needs to be some sort offeedstock analysis. While the DEQhas some data, itis very limited. The only element ofthis type offacility that can currently be easily quantified is howmuch natural gas is beingburned. d. Teri Ikeda asked Kip ifhe had any thoughts onthe analytical element of the timeperiod over which this data would be available. The older facilities would be able to provide this historical data, butitmaynot.be available for the newer facilities. 

### Kip answered thatthere is a "goodthrough" date issuedwith the Oregon certification. This is a wayto 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 trackingtheir output, particularly about peaking. 

### Kip answered that interms oftracking the generation, the typical approach is to create a spreadsheetthatkeeps track ofhourly activity. WREGIS knows what the capacity ofa facility is, so cantell ifthe report is more than what is possible. 

### f. Tom 0'Connor asked about the analysis ofa 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 thatthe generator's output is complying with expectations. WREGIS can forcibly retire RECs inthe case offraud

- ifthe operator didnot g. Juliet Johnson asked howCaliforniahas beenhandling this situation. She suggested having a conservative standard for the amciunt ofnatural gas that is feeding into the system. Ifan applicant wants to argue that they have a super-efficient way ofoperating, thenthe burden is onthem to prove thatthe standard should not apply to them and that they should have a more favorable efficiency. Kip said thather ideatracks a conversation that he has had with EWEB.
4UM

__- PGE 2012 RPS Complicance Report Attachment E 

## RPS2010AdvisoryCommittee. **~eeting** 

### Meeting #4 Minutes

9:00am to 3:30pm Oregon Dept. of Transportation, Portland, OR Page 52



### h. Doris Penwell asked ifODOE regularly goes back and monitors generating units. Kip repliedthatthe only multi-fuel facility that has ever made itthroughthe certificationprocess soon stopped operating. He would like to have proxy accessto the data spreadsheets inthe future. 

### 3. The committee discussed theissue ofupgrades. 1. 

### This ispossiblyrelevant even to a facility thatis part ofthepre-1995 biomass that is now eligible. 2. Commenced operation question a. The committee has talked about howthis issue compares to the California _::.; RPS and the Green-e program. Californiahas an investment threshold and ·2 

### a requirementthatthe prime moveris replaced. Ifa facility completely modifies its fuel source, then also treated as a new facility.
·**~:** 

### b. Could.have a **con~ervative** 

### standard, such as aninvestmentthreshold, or if :.. it meets the Green-e requirement, then Oregonwould accept it as a new facility. c. Kip askedthe Committee for comments orthoughts onrule language. MeganWalseth-Decker stated that she is in fa':'or ofkeeping this area as simple as possible and likes the Green-e standard. She also statedthat she is wary ofhowmuch room the phrase "become operational'' gives the group. d. Brendanresponded sayinghe believes that ODOE has broad rulemaking authority inthis areabased onpolicy statements. Believes the question is whetherthe phrase "becomes operational" is aninexactterm or a delicative term, and whether that distinction matters. 3. General protocols for dealing withupgrades a. The group discussedthe importance ofthe phrase "becomes operational." BrendanMcCarthy stated that SB 83 8 is unclear onwho has implementation authority. b. The group identified some oftheissues associated with determining a facility's operational date. Discussed what type ofinvestments in an existing facility could cause itto be considered a newfacility for the purposes ofthe RPS. Juliet Johnson ofthe PUCraised thepoint about ifa facility were to switchfuel sources. c. The group discussed howthe CaliforniaRPS has approached this issue. d. MeganDecker commented that Oregon shouldtry and encourage investment innew 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, couldbe an alternative to basing the decisionpurely on investment levels. 

### f JeffBissonnette stated thathe was uncomfortable usingthe investment level as the bar. He gave the analogythat a newengine is notthe same as a
5UM - PGE 2012 RPS Complicance Report 

### RPS2010AdvisoryCommittee Meeting **M~eting** 

### #4 Minutes

9:00am to 3:30pm Oregon Dept. ofTransportation, Portland, OR Attachment E Page 53



### new car. He added thatthe 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 efficiencyupgrades are not. · b. Rick Oliver raised the question ofwhat constitutes the "generating unit" for a hydro facility. c. BrendanMcCarthyprovidedthree scenarios where PGE is dealing with this issue. d. The group discussed how best to establish the baseline. 5. Oregon share ofthe federal project upgrades 4. Bundled/Unbundled REC issues · 

### 1. 

### JasonHeuser described EWEB> s power swap agreements> which do not create NERC e-tags> and whyEWEB believes the QE should still be counted as bundled RECs. Kip voiced his concernthatthis situation aligns withthe statute. 5. Stranded Generation 

### 1. Kip reviewed some ofthe options thatthe group has discussed before. a. WREGIS. PCR 192 will be discussed at anupcoming WREGIS meeting. The group would need to consider any fmancial implications ofgoing this route. i. BrendanMcCarthy said he was concerned that the rulemaking would end before the group resolved the issue. b. Interimsystem. Kip is concerned with this route for several reasons> includingpotential double-counting ofRECs> and establishing an end date. 1. 

### Betsy Kauffman said thatthe ETO was veryinterested inthis 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. JeffBissonnette suggested thatthere maybe other ways for RECs to benefitratepayers. Couldbe sold to voluntary markets. 111. 

### Several group members objected to the idea ofa parallel tracking system with no end date. Specifically, because ofverification issues. iv. Kip added that voluntaryprograms 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 potentialproblem with using attestations·is the lack ofclarity ofwhetherthese would go to ODOE orthe PUC. Kip does not
6UM

__- PGE 2012 RPS Complicance Report AttachmentE 

### RPS 2010Advisory Committee Meeting Meeting #4 Minutes

9:00am to 3:30pm Page 54


### Oregon Dept. ofTransportation, Portland, OR



### c. 

### NARR.know the answer, butpointedto the fact that some utilities do not report to the PUC. i. 

### The group decided that it would be bestto wait onthis option until after "WREGIS makes a decision.

7UM _- PGE 2012 RPS Complicance Report Attachment E Page 55



## RENEW ABLE ENERGYPRODUCTION TAX CREDIT: INSTRUCTIONS FORREQUESTING CERTIFICATION OF INCREMENTAL HYDROPOWERPRODUCTION PURSUANT TO THE ENERGY POLICYACT OF 2005

FEDERAL ENERGYREGULATORY COMMISSION OFFICE OFENERGY PROJECTS DIVISIONOFHYDROPOWERADMINISTRATION& 

### COMPLIANCE Updated & 

### Posted onFERC;s websiteMarch 2007UM - PGE 2012 RPS Complicance Report



### ENERGYPOLICYACT OF 2005 RENEW ABLE ENERGYPRODUCTION TAX CREDIT Attachment E Page 56_

Thispaperwaspreparedby Commission's staff anddoes notnecessarily reflect the views of other members of the FederalEnergyRegulatory Commission. 

### EPAct 2005 -Hydroelectric Tax Credit 11UM

__- PGE 2012 RPS Complicance Report Attachment E Page 57



### SUlVIMARY

Section 45 ofthe Internal Revenue Code of 1986 provides a renewable energy tax credit to owners or operators ofelectric generation facilities that produce electricity from "qualified energyresources" at "qualified facilities," placedinto service by specified dates. Section 1301 ofthe Energy PolicyAct of2005 amends Code section 45 to apply the credit to incrementalproduction 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·ofinformatwnthe 

# ~;=!s~~t~~~~i\~l~~l~~~~~i;:~~~~~.~~~~o~

. , ..**"'~:'i;}~~l~ll;; ¥~:;,i**  "'"'#'

EPAct 2005 -HydroelectricTax Credit iiiUM

- PGE 2012 RPS Complicance Report



## CONTENTS Attachment E Page 58,



### Page I. Changes to theInternalRevenue Service Code

...................................................... 1 II. Certification Procedures

........................................................................................ 2 A. Certification ofBaselineAnnualHydropower Production

............................ 2 B. Percentage ofAnnualHydropower Production Attributable to Efficiency Improvements orAdditions ofCapacity

..................................................................... 3 ill. 

### Instructions for Requesting Certification.:

.......................................................... 5 A. HistoricAverageAnnual Production (baseline):

...................... 5 B. Percentage of Attributable to Efficiency

.......;........................... 5

EP Act 2005 -Hydroelectric Tax Credit 

### ivUM_- 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 ENERGYPRODUCTION TAX CREDIT

I. Changes to the InternalRevenue Service Code Section 45 ofthe Internal Revenue Code of 1986 1 

### provides a renewable energy tax creditto owners or operators ofelectric generation facilities thatproduce electricity from "qualifiedenergy resources" at "qualified facilities," placedinto serviceby specified dates.2 

### The credit, whichis 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 irrigationpower, municipal solid waste andpoultry 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 "qualifiedhydropowerproduction." 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 notrelevanthere. EPAct 2005 -Hydroelectric Tax Credit 

### 1UM

- PGE 2012 RPS Complicance Report Attachment E Page 60.



### ten years, and begins on the in-service date ofthe qualifying efficiency improvement or capacityaddition.6
, 

### Section 1301 amends Code section 45 to provide thatthe incremental hydropower production at an existing facility for any taxable year is equal to the percentage of average annual hydropowerproduction at the facility attributable to the efficiency improvements or additions ofcapacityplaced in service ·after the date ofenactment, determined byusing the same water flow information used to determine an historic average annual hydropower production baseline for such facility. The incremental hydropower production maynotbe based on operational changes unless they are directly associatedwiththe effiCiency improvements or additions ofcapacity. The Commission is requiredto certify the percentage andthe baseline.7 

### In 

### order for a capacity **additiontQ~.,R9Jl:llY(]roelectric** 

### dam to qualify, the dam mustbe licensedbythe 

### 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 dammusthave been 

### place4Jn:S,ecyi~eprio~tQ,.t11e~nadriiell1:;o£EPAct 2005, but did not generatehydroelectric 

## P8~~~:\:~f9g~,t~at~~~fi~~i§~ **is'·~~!~~94.;~,.ff**_licensedproject. There canbe no **enlargew.~;n,tqf.J~.~4Jivet~I9P,Strq'Ctuf.t:\~q9.-BSAAG.ttpn** 

### or enlargement ofa 

# ~~:.**;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 notrequrre



### II. 

# :~rtifi::~!i{~~. 

# :.. •i

# !.(~

hydropowerproduction baseline, referrfiig:'(irilyt6'theuse of"water flow information." Water flow often does not correspond directly to powerproduction, because many projects are operated in a storage and release mode, have instream flow, fish passage, or other flow requirements thatpreclude orrestrict generation at certain times to address environmental concerns, andbecause flows at certain times ofthe year may exceed the hydraulic capacity ofthe project's turbines.

6 

### New subparagraph 45(d)(9), added byEPAct 2005 section 130l(c)(4).
7 

### Code section 45(c )(8)(B)(i) and (ii), as revisedbyEPAct 2005 section 130l(c)(3). 8 

### Code section 45(c)(8)(C), as revisedbyEPAct 2005 section 1301(c)(3). EPAct 2005 -Hydroelectric Tax Credit 2UM

__- PGE 2012 RPS Complicance Report Attachment E Page 61



## .x ...e::e.
.. .... . . ....... . **~zeaoMx** 

## ... ..

## oz... x. .&

. 24 .k 

### Under these circumstances, we willnot establish a formula for calculating the baseline. Rather, licensees should submit for Commissionreview and certification the historic average annual hydropowerproductionbaseline theybelieve to be appropriate for the facility in question, along with the supporting calculation and water flow data. The Commissionmayrequest additional or revised data ifthatis necessary to complete its analysis. 

### B. Percentage ofAnnualHydropower Production Attributable to Efficiency Improvements orAdditions ofCapacity Calculating the percentage ofannual hydropowerproduction 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.'::!.) •• ..'.\·· ·/'··:·'·'/ '•··:·-_:·.'/ **.·;·.-:~** 

### ofupgrades to **genera~~#iq~;;wr1)1jfe,s}:~ E~ampl~si'inc.lud~**  **i~Wffidii1!fgenerators,** 

### replacing

-· **-,\·-~-;-,.-**
.._, **-_··~~-':··:-:'-.:;}----_,..** '-:.·.-'.! ,_ ·.' '·'. ,_; .._, \r **.~** ..• .. **~,.** ::.'·\:·i **::·'.··.'-..·.,,~,··:·'··.** ,,·· ..--' 

### turbines withmore **efficien,t,uiiits~ 1** **:ari.d''coinputep.~iri:g',PQi.i~d1\offittbines** 

### and generators 

# :~:=~=~~~llflill&~illit(lf:r:~~::ple
ofaddition ofcapacity 

### 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 Commissionto certify the percentage of annualpowerproduction attributable to the efficiency improvements or additions of capacity. We interpret this to require us to certify the percentagejust once, using the established average annual generation baseline andthe incremental generation calculated when the project operator seeks authorization for the efficiency upgrade or addition to capacity. For instance, ifthe historic average annual generation has been 1,000,000 kWh andan efficiency upgrade would enable the projectto generate 1,100,000 kWh, we would

9 

### Because new Code section 45(c)(8) distinguishes "operational changes" from "additions ofcapacity," we conclude that Congress did not intendto apply the credit to additions ofcapacity resulting solelyfrom operational changes such as increasing the reservoir level orswitching from run-of-river to peaking operation. 

## EPAct 2005 -Hydroelectric Tax Credit 3UM - PGE 2012 RPS Complicance Report Attachment E Page 62 ·



### certifythattenpercent ofthe average annual generation is attributable to the upgrade. We will allow a one-time recertification ofthepercentage ifapplicants can demonstrate such a need due to fluctuations 

### in generation attributable to the efficiency improvements.

EP Act 2005 -Hydroelectric Tax Credit 4UM

__- PGE 2012 RPS Complicance Report Attachment E Page 63

ML#

.............Xi

... .$$$$

. ...........$

.... ... ........

### ;:



### ill. 

### Instructions for Requesting Certification Licensees and exemptees that intendto seek a renewable energy production tax credit for efficiency improvements or additions ofcapacity atexisting facilities pursuant to Internal Revenue Service Code section 45 are requiredto provide the Internal Revenue Service with certificationfrom the Commission. The Commission is requiredto certify
· the "historic average annual hydropower production" andthe "percentage ofaverage

annual hydropowerproduction at the facility attributable to the efficiency improvements or additions ofcapacity" placedin service after August 8, 2005 andbefore January 1, 2009. Forthis 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 usedto support the calculation ofHistoric Average Annual Hydropower Productionbaseline. 3. Calculations showing the percentage ofaverage annual hydropower production attributable to the efficiency improvements or additions of capacity. 4. Proposed in-service date. Anyrequests for Certification mustbe filed withthe 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 Act2005 -Hydroelectric Tax Credit 

### 5

## Sample Order

EP Act 2005 -Hydroelectric Tax Credit UM

- PGE 2012 RPS Complicance Report Attachment E Page 64,



### 6UM_- 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 HYDROPOWERGENERATION FORIRS SECTION45 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 certificationfor 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 bythe licensee/exemptee we certify the following: ·,, 

### ;~;;::;_;{f,i;\i;·i\;;fJt!~lt~r;,t~~\~;~;:-P'~!"'~-· 

# .

EP Act2005 -Hydroelectric Tax Credit 

### 7UM - PGE 2012 RPS Complicance Report Attachment E Page 66.



### (B) This order constitutes fmal agency action. Requests for rehearing bythe Commission maybe filed within 30 days ofthe date ofissuance ofthis order, pursuant to 18 C.P.R.§ 385.713.

[Official's Signature] ·

EPAct 2005

- Hydroelectric Tax Credit 8