SECOND	RECIRCULATED	DRAFT	EIR

FOR	THE

SIERRA	PACIFIC	COGENERATION	POWER PROJECT

SCH#	2009072011

FEBRUARY	2012

Prepared	for:

Shasta	County	Department	of	Resource	Management

Planning	Division

1855	Placer	Street,	Suite	103

Redding,	CA		96001

(530)	225-5532

Prepared	by:

De	Novo	Planning	Group

4630	Brand	Way

Sacramento,	CA	95819

(916)	949-3231

De	Novo	Planning	Group

A	Land	Use	Planning,	Design,	 and	Environmental	Firm

SECOND	RECIRCULATED	DRAFT	EIR

FOR	THE

SIERRA	PACIFIC	COGENERATION	POWER	PROJECT

SCH# 2009072011

FEBRUARY	2012

Prepared	for:

Shasta	County	Department	of	Resource	Management

Planning	Division

1855	Placer	Street,	Suite	103

Redding,	CA		96001

(530)	225-5532

Prepared	by:

De	Novo	Planning	Group

4630	Brand	Way

Sacramento,	CA	95819

(916)	949-3231

TABLE	OF	CONTENTS 2012

Second	Recirculated	Draft	EIR –	SPI	Cogeneration	Power	Project TOC-1

SECOND	RECIRCULATED	DRAFT	EIR

Chapter Page	Number

1.0	 Introduction........................................................................................................................1.0-1

1.1	Introduction............................................................................................................1.0-1

1.2	Project	Background	and	Reasons	for	EIR	Recirculation..........................................1.0-2

1.3	Summary	of	Changes..............................................................................................1.0-3

1.4	Comments	on	the	Second	Recirculated	Draft	EIR ..................................................1.0-3

1.5	Public	Notice/Public	Review ...................................................................................1.0-4

1.6	Organization	of	the	Document...............................................................................1.0-5

2.0		Greenhouse	Gases	and	Climate	Change.............................................................................2.0-1

2.1	Environmental	Setting ............................................................................................2.0-1

2.2 Regulatory	Setting ..................................................................................................2.0-6

2.3 Impacts	and	Mitigation	Measures........................................................................2.0-15

Table Page	Number

Table	A:		Inventory,	Harvest	and	Growth ................................................................................2.0-23

Table	2-1:	Methodologies	Used	to	Estimate	GHG	Emissions	for	the	Project..........................2.0-27

Table	2-2:	Construction	Greenhouse	Gases	 ...........................................................................2.0-29

Table	2-3:	Representative	Woody	Biomass	Fuel	Mix	of	Project..............................................2.0-31

Table	2-4:	Direct	and	Net	GHG	Emissions	Generated	by	the	Project......................................2.0-33

Figure Page	Number

Figure	1:	Tree	Diameters	Over	Time........................................................................................2.0-22

Figure	2:	Inventory,	Harvest	and	Growth ................................................................................2.0-23

Figure	3:	Habitat	Distribution	Change	Over	Time....................................................................2.0-24

Appendices

Appendix	A – GHG	Calculation	Worksheets
2012 TABLE	OF	CONTENTS

TOC-2 Second	Recirculated	Draft	EIR –	SPI	Cogeneration	Power	Project

This	page	left	intentionally	blank.		
1.0 INTRODUCTION 2012

Second	Recirculated	Draft	EIR	–	SPI	Cogeneration	Power	Project 1.0-1

This	 section	 summarizes	 the	 purpose	 of	 the	 Second	 Recirculated	 Draft	 Environmental	 Impact	

Report	 (EIR)	 for	 the	 Sierra	 Pacific	 Industries	 (SPI)	 Cogeneration	 Power	 Project	 (project).	 The	

following	discussion	addresses	the	environmental	procedures	that	are	to	be	followed	according	to	

State	 law;	 the	 intended	 uses	 of	 the	 Second	 Recirculated	 Draft	 EIR;	 the	 contents	 of	 the	 Second	

Recirculated	Draft	EIR;	the	procedures	for	submittal	of	public	and	agency	comments	on	the	Second	

Recirculated	Draft	EIR;	and	the	requirements	for	responding	to	comments	on	the	original	Draft	EIR,	

the	Recirculated	Draft	EIR	and	the	Second	Recirculated	Draft	EIR. 				

1.1 INTRODUCTION

The	 California	 Environmental	 Quality	 Act	 (CEQA)	 requires	 that	 all	 state	 and	 local	 government	

agencies	 consider	 the	 environmental	 consequences	 of	 programs	 and	 projects	 over	 which	 they	

have	 discretionary	authority	 before	 taking	action	 on	 those	 projects	 or	 programs.	Where	 there	is	

substantial	evidence	 that	a	project	may	have	a	significant	effect	on	 the	environment,	the	agency	

shall	prepare	an	environmental	impact	report	(EIR)	(CEQA	Guidelines,	Section	15164[a]).	An	EIR	is	

an	informational	document	that	will	inform	public	agency	decision	makers	and	the	general	public	

of	 the	 significant	 environmental	 effects	 of	 a	 project,	 identify	 possible	 ways	 to	 minimize	 the	

significant	effects,	and	describe	reasonable	alternatives	to	the	project.

CEQA	requires	that	a	Draft	EIR	be	prepared	and	circulated	for	public	review.	Following	the	close	of	

the	 public	 review	 period,	 the	 lead	 agency	 prepares	 a	 Final	 EIR,	 which	 includes	 the	 comments	

received	 during	 the	 review	 period	 (either	 verbatim	 or	 in	 summary),	 and	 responses	 to	 the	

significant	environmental	 issues	 raised	 in	 those	 comments.	 Prior	 to	 taking	action	 on	a	 proposed	

project,	the	lead	agency	must	certify	the	EIR	and	make	certain	findings.

A	 lead	agency	 is	 required	 to	 recirculate	a	Draft	EIR,	 prior	 to	 certification,	when	 “significant	 new	

information”	is	added	 to	 the	EIR	after	 the	 public	 review	 period	 begins	 (CEQA	Guidelines	Section	

15088.5).	New	information	is	deemed	significant	if	it	reveals	the	following:

•	A	new	significant	environmental	impact	resulting	from	either	the	project	itself	or	a	new	

proposed	mitigation	measure;

•	 A	 substantial	 increase	 in	 the	 severity	 of	 an	 environmental	 impact	 would	 result	 unless	

mitigation	measures	are	adopted	that	reduce	the	impact	to	a	level	of	insignificance;

•	A	 feasible	project	alternative	or	mitigation	measure	considerably	different	 from	others	

previously	 analyzed	 would	 clearly	 lessen	 the	 significant	 environmental	 impacts	 of	 the	

project,	but	the	project	proponent	declines	to	adopt	it;	or

•	 The	 Draft	 EIR	 was	 so	 fundamentally	 inadequate	 and	 conclusory	 that	 it	 precluded	

meaningful	public	review	and	comment.

In	 addition,	 a	 lead	 agency	may	 choose	 to	 recirculate	 an	EIR	 if	 additional	 studies	 or	 analyses	 are

conducted	 for	 a	 project	 before	 a	 specific	 action	 is	 taken	 by	 local	 decision	 makers	 to	 approve	 a	
2012 1.0 INTRODUCTION

1.0-2 Second	Recirculated	Draft	EIR	–	SPI	Cogeneration	Power	Project

project.	 	 Recirculation	 may	 be	 limited	 to	 those	 chapters	 or	 portions	 of	 the	 EIR	 that	 have	 been	

modified	(CEQA	Guidelines	Section	15088.5(c).			

1.2 PROJECT	BACKGROUND	AND	REASONS	FOR	EIR RECIRCULATION

Notice	of	Preparation

The	 County	 circulated	 a	 Notice	 of	 Preparation	 (NOP)	 of	 an	 EIR	 for	 the	 proposed	 project	 and	 an	

Initial	Study	on	July	3,	2009	to	trustee	and	responsible	agencies,	the	State	Clearinghouse,	and	the	

public.		A	public	scoping	meeting	was	held	on	 July	21,	2009.		Concerns	 raised	in	 response	 to	 the	

NOP	were	considered	during	preparation	of	the	Draft	EIR.		

Draft	EIR

The	County	circulated	a	Draft	EIR	to	the	State	Clearinghouse,	trustee	and	responsible	agencies,	and	

the	public	on	August	6,	2010.		A	Notice	of	Completion	(NOC)	was	filed,	and	a	45-day	public	review	

period	 was	 provided	 between	 August	 6,	 2010	 and	 September	 21,	 2010	 to	 receive	 public	 and	

agency	comments	on	the	adequacy	of	the	environmental	analysis	contained	in	the	Draft	EIR.		The	

Draft	 EIR	 contains	 a	 description	 of	 the	 project,	 description	 of	 the	 environmental	 setting,	

identification	of	project	impacts,	and	mitigation	measures	 for	impacts	 found	 to	be	significant,	as	

well	 as	 an	 analysis	 of	 project	 alternatives,	 identification	 of	 significant	 irreversible	environmental	

changes,	 growth-inducing	 impacts,	 and	 cumulative	 impacts.	 	 The	 Draft	 EIR	 identifies	 issues	

determined	to	have	no	impact	or	a	less	than	significant	impact,	and	provides	detailed	analysis	of	

potentially	significant	and	significant	impacts.		The	original	Draft	EIR	concluded	that	the	proposed	

project	 would	 result	 in	 a	 significant	 and	 unavoidable	 impact	 to	 greenhouse	 gases	 (GHGs)	 and	

global	climate	change.

Recirculated	Draft	EIR

The	County	received	numerous	comments	on	the	original	Draft	EIR	relating	to	the	analysis	of	GHGs	

and	 climate	 change.	 	 In	 light	 of	 the	 comments	 received,	 the	 County	 determined	 that	 the	

preparation	of	a	revised	GHG	analysis	was	warranted.		The	County	then	oversaw	preparation	of	a	

revised	 GHG	 and	 climate	 change	 analysis	 that	 employed	 a	 more	 refined	 and	 comprehensive	

methodology, including	the	use	of	a	qualitative	threshold	of	significance	for	the	GHG	analysis, and	

utilized	the	expanded	fuel	supply	information	provided	by	the	project	applicant.		

The	 County	prepared	and	 circulated	a	 Recirculated	Draft	EIR	to	 the	State	 Clearinghouse,	 trustee	

and	responsible	agencies,	the	public,	and	all	parties	and	individuals	that	submitted	comments	on	

the	original	Draft	EIR	on	September	2,	2011.	A	Notice	of	Completion	(NOC)	was	filed,	and	a	45-day	

public	review	period	was	provided	between	September	2,	2011	and	October	17,	2011	 to	 receive	

public	 and	 agency	 comments	 on	 the	 adequacy	 of	 the	 environmental	 analysis	 contained	 in	 the	

Recirculated	 Draft	 EIR.	 	 The	 Recirculated	 Draft	 EIR	 included	 additional	 details	 regarding	 the	

project’s	fuel	supplies	and	a	revised	greenhouse	gas	(GHG)	analysis.		
1.0 INTRODUCTION 2012

Second	Recirculated	Draft	EIR	–	SPI	Cogeneration	Power	Project 1.0-3

The	revised	GHG	and	climate	change	analysis	contained	in	the	Recirculated	Draft	EIR	resulted	in	a	

conclusion	 that	 impacts	 to	 greenhouse	 gases	 and	 global	 climate	 change	 associated	 with	 the	

proposed	project	would	be	less	than	significant.		

REASONS	FOR	THE	SECOND	RECIRCULATED	DRAFT	EIR

The	 Recirculated	Draft	EIR	 utilized	a	 qualitative,	 or	 non-numeric,	 threshold	 of	 significance	in	 the	

GHG	 analysis.	 	 The	 analysis	 of	 GHGs	 in	 the	 Recirculated	 Draft	 EIR	 concluded	 that	 the	 proposed	

project	 would	 result	 in	 less	 than	 significant	 impacts	 related	to	 GHGs	 and	 climate	 change.	 	 The	

County	received	comments	on	the	Recirculated	Draft	EIR	that	challenged	the	use	of	a	qualitative	

threshold	 of	 significance.	 	 Comments	 on	 the	 Recirculated	 Draft	 EIR	 suggested	 that	 the	 use	 of	 a	

quantitative	threshold	of	significance	for	the	GHG	analysis	was	more	appropriate.		In	light	of	these	

comments,	the	County	has	determined	that	the	use	and	application	of	a	quantitative	threshold	is

in	fact	appropriate.

This	Second	Recirculated	Draft	EIR	includes	a	revised	analysis	of	GHG	impacts	that	may	result	from	

project	 implementation,	 and	 utilizes	 a	 quantitative	 threshold	 of	 significance.	 	 The	 impact	

determination	 related	 to	 GHGs	 in	 this	 Second	 Recirculated	 Draft	 EIR	 has	 not	 changed	 when	

compared	to	the	Recirculated	Draft	EIR;	both	documents	have	determined	that	impacts	related	to	

GHGs	 would	 be	 less	 than	 significant.	 	 However,	 the	 County	 has	 elected	 to	 circulate	 this	 Second	

Recirculated	Draft	EIR	to	provide	the	public	and	interested	agencies	an	opportunity	to	review	and	

comment	 on	 this	 revised	 approach	 and	 the	 use	 of	 a	 numeric	 threshold	 of	 significance	 for	 GHG	

impacts.		

Procedures	 for	 commenting	 on	 this	 revised	 analysis	 in	 the	 Second	 Recirculated	 Draft	 EIR	 are	

detailed	below.			

1.3 SUMMARY	OF	CHANGES

One	 section	 of	 the	 Recirculated	 Draft	 EIR	 has	 been	 revised	 and	 is	 included	 in	 this	 Second	

Recirculated	Draft	EIR.		The	Greenhouse	Gas	and	Climate	Change	Section	of	the	Recirculated	Draft	

EIR	has	been	revised,	and	is	included	in	this	document	for	public	review	and	comment.		The	GHG	

analysis	 in	 this	 Second	 Recirculated	 Draft	 EIR	 supplants	 and	 replaces	 the	 GHG	 analysis	 that	 was	

included	in	the	Recirculated	Draft	EIR.		As	described	above,	the	significance	conclusions	related	to	

GHGs	and	climate	change	have	not	changed.		However,	this	Second	Recirculated	Draft	EIR	utilizes	a	

numeric	 threshold	 of	 significance	 to	 determine	 the	 significance	 of	 GHG	 and	 climate	 change	

impacts,	while	the	Recirculated	Draft	EIR	utilized	a	qualitative	threshold	of	significance.		

No	changes	 to	 the	Project	Description	have	been	made	as	part	of	 this	Second	Recirculated	Draft	

EIR.	 	 The	 Project	 Description,	 which	 was	 included	 as	 Section	 2.0	 of	 the	 Recirculated	 Draft	 EIR,	

describes	 the	 full	 range	 of	 actions	 and	 activities	 contemplated	 under	 CEQA	 for	 the	 proposed	

project.		
2012 1.0 INTRODUCTION

1.0-4 Second	Recirculated	Draft	EIR	–	SPI	Cogeneration	Power	Project

1.4 COMMENTS	ON	THE	SECOND	RECIRCULATED	DRAFT	EIR

In	accordance	with	Section	15088.5(f)(2)	of	 the	CEQA	Guidelines,	“When	an	EIR	is	revised	only	in	

part	and	the	lead	agency	is	recirculating	only	the	revised	chapters	or	portions	of	the	EIR,	the	lead

agency	may	request	that	reviewers	limit	their	comments	to	the	revised	chapters	or	portions	of	the	

recirculated	 EIR.	 	 The	 lead	 agency	 need	 only	 respond	 to	 (i)	 comments	 received	 during	 the	 initial	

circulation	 period	 that	 relate	 to	 chapters	 or	 portions	 of	 the	 document	 that	were	not	 revised	 and	

recirculated,	and	(ii)	comments	received	during	the	recirculation	period	that	relate	to	the	chapters	

or	portions	of	the	earlier	EIR	that	were	revised	and	recirculated.”

The	SPI	Cogeneration	Power	Project	Draft	EIR	was	originally	circulated	for	a	45-day	public	review	

and	comment	period	between	August	6,	2010	and	September	21,	2010.		The	Recirculated	Draft	EIR	

was	circulated	 for	a	45-day	public	 review	and	comment	period	between	September	2,	2011	and	

October	17,	2011.		

The	County	of	Shasta,	acting	as	the	lead	agency	for	the	project,	formally	requests	that	reviewers	of	

the	 Second	 Recirculated	 Draft	 EIR	 limit	 their	 comments	 to	 the	 revised	 portions	 of	 the	

Recirculated	Draft	EIR	included	herein.		

The	Final	EIR,	which	will	 be	 prepared	after	 the	 public	 review	 period	 for	 the	Second	Recirculated	

Draft	EIR,	will	include	responses	to	comments	received	on	all	sections	of	the	original	Draft	EIR	that	

were	not	recirculated,	responses	to	comments	received	on	the	Recirculated	Draft	EIR	that	relate	to	

the	 portions	 that	 were	 Recirculated	 but	 not	 included	 in	 the	 Second	 Recirculated	 Draft	 EIR	(the	

Project	Description),	and	 responses	 to	comments	 received	on	 the	Second	Recirculated	Draft	EIR.		

In	other	words,	comments	related	to	the	GHG	and	climate	change	analysis	included	in	the	original	

Draft	EIR	and	Recirculated	Draft	EIR	will	not	be	included	in	the	Final	EIR	responses	to	comments.		

Comments	and	responses	related	to	the	GHG	and	climate	change	analysis	contained	in	this	Second	

Recirculated	Draft	EIR	will	be	included	in	the	Final	EIR.		

1.5 PUBLIC	NOTICE/PUBLIC	REVIEW

CEQA	 requires	a	 public	 review	period	 of	at	 least	45 days	 for	a	 recirculated	 draft	EIR	 (Guidelines	

Sections	15088.5	and	15105).		Additionally,	Public	Resources	Code	Section	21092.1	requires	Shasta	

County	to	send	a	notice	of	recirculation	to	every	agency,	person,	or	organization	that	commented	

on	the	original	Draft	EIR	and	the	Recirculated	Draft	EIR.		Consistent	with	CEQA,	the	review	period	

for	 this	 Recirculated	 Draft	 EIR	 is	 forty-five (45)	 days.	 County	 Planning	 staff	 will	 be	 available	 to	

answer	questions	from	the	public	regarding	the	Second	Recirculated	Draft	EIR.		Public	comment	on	

the	 Second	 Recirculated	 Draft	 EIR	 will	 be	 accepted	 in	 written	 form.	 All	 comments	 or	 questions	

regarding	the	Second	Recirculated	Draft	EIR	should	be	addressed	to:

Lio	Salazar,	Associate	Planner

Shasta	County	Department	of	Resource	Management,	Planning	Division

1855	Placer	Street,	Suite	103

Redding,	CA	96001

(530)	225-5532
1.0 INTRODUCTION 2012

Second	Recirculated	Draft	EIR	–	SPI	Cogeneration	Power	Project 1.0-5

RESPONSE	TO	COMMENTS/FINAL	EIR

Following	 the	 public	 review	 period,	 a	 Final	 EIR	 will	 be	 prepared.	 	 The	 Final	 EIR	 will	 include	

responses	to	comments	received	on	all	sections	of	the	original	Draft	EIR	and	Recirculated	Draft	EIR	

that	were	not	recirculated,	and	responses	to	comments	received	on	the	Second	Recirculated	Draft	

EIR	that	relate	to	the	portions	that	were	recirculated.		

CERTIFICATION	OF	THE	EIR/PROJECT	CONSIDERATION	

The	County	will	review	and	consider	the	Final	EIR.		If	the	County	finds	that	the	Final	EIR	is	adequate	

and	 completed	 in	 compliance	 with	 CEQA,	 the	 Planning	 Commission	 may	 certify	 the	 Final	 EIR	 in	

accordance	with	CEQA.	As	set	forth	by	CEQA	Guidelines	Section	15151,	the	standards	of	adequacy	

require	an	EIR	 to	provide	a	sufficient	degree	of	analysis	 to	allow	decisions	 to	be	made	 regarding	

the	proposed	project	that	intelligently	take	account	of	environmental	consequences.		

Following	 review	 and	 consideration	 of	 the	 Final	 EIR,	 the	 County	 may	 take	 action	 to	 approve,	

modify,	or	 reject	 the	 project.	A	 decision	 to	approve	 the	 proposed	 project,	 for	which	 the	original	

Draft	EIR	identifies	significant	environmental	effects,	must	be	accompanied	by	written	findings	in	

accordance	 with	 State	 CEQA	 Guidelines	 Sections	 15091	 and	 15093.	 	 A	 Mitigation	 Monitoring	

Program	would	also	be	adopted	in	accordance	with	Public	Resources	Code	Section	21081.6(a)	and	

CEQA	 Guidelines	 Section	 15097	 for	 mitigation	 measures	 that	 have	 been	 incorporated	 into	 or	

imposed	 upon	 the	 project	 to	 reduce	 or	 avoid	 significant	 effects	 on	 the	 environment.	 	 This

Mitigation	 Monitoring	 Program	 will	 be	 designed	 to	 ensure	 that	 these	 measures	 are	 carried	 out	

during	project	implementation,	in	a	manner	that	is	consistent	with	the	EIR.

1.6 ORGANIZATION	OF	THE	DOCUMENT

This	Second	Recirculated	Draft	EIR	includes	two	chapters	as	follows:

CHAPTER	1.0 – INTRODUCTION

This	 chapter	 summarizes	 the	 purpose	 of	 the	 Second	 Recirculated	 Draft	 EIR,	 describes	 the	

environmental	procedures	that	are	to	be	followed	according	to	State	law,	the	intended	uses	of	the	

Second	 Recirculated	 Draft	 EIR,	 the	 contents	 of	 the	 Second	 Recirculated	 Draft	 EIR,	 including	 a	

summary	of	changes	made	to	the	original	Draft	EIR	and	Recirculated	Draft	EIR,	the	procedures	for	

submittal	 of	 public	 and	 agency	 comments	 on	 the	 Second	 Recirculated	 Draft	 EIR,	 and	 the	

requirements	for	responding	to	comments	on	the	original	Draft	EIR,	the	Recirculated	Draft	EIR,	and	

the	Second	Recirculated	Draft	EIR.				

REVISED	CHAPTER	2.0 – GREENHOUSE	GASES	AND	CLIMATE	CHANGE

Chapter	 2.0	 provides	 background	 information	 on	 the	 existing	 environmental	 and	 regulatory	

settings	as	they	relate	to	GHGs	and	climate	change,	identifies	the	methodologies	used	to	complete	

the	GHG	analysis,	identifies	the	thresholds	of	significance	used	in	the	analysis,	and	includes	both	a	

quantitative	 and	 qualitative	 analysis	 of	 the	 proposed	 project’s	 impacts	 related	 to	 GHGs	 and	

climate	 change.	 	 The	 GHG	 and	 climate	 change	 analysis	 has	 been	 revised	 to	 include	 new	
2012 1.0 INTRODUCTION

1.0-6 Second	Recirculated	Draft	EIR	–	SPI	Cogeneration	Power	Project

quantitative	 thresholds	 of	 significance	 to	 assess	 impacts	 related	 to	 GHGs	 generated	 by	 the	

proposed	project,	as	previously	described.	The	original	Draft	EIR	concluded	that	impacts	related	to	

GHGs	and	global	climate	change	would	be	significant	and	unavoidable.		The	Recirculated	Draft	EIR	

and	Second	Recirculated	Draft	EIR	both	conclude	that	impacts	related	to	GHGs	and	global	climate	

change	would	be	less	than	significant.		
2.0 GREENHOUSE	GASES	AND	CLIMATE	CHANGE 2012

Second	Recirculated	Draft	EIR	–	SPI	Cogeneration	Power	Project 2.0-1

2.0 GREENHOUSE	GASES	AND	CLIMATE	CHANGE

The	 following	 section	 provides	 a	 summary	 of	 greenhouse	 gases	 and	 climate	 change	 linkages,	

discusses	 the	 potential	 global	 and	 localized	 (State	 of	 California)	 effects	 of	 climate	 change,	

summarizes	the	applicable	regulatory	setting	related	to	climate	change	and	greenhouse	gases,	and	

discusses	the	proposed	project’s	potential	to	result	in	cumulative	climate	change	impacts.		

As	described	in	greater	detail	below,	emissions	of	greenhouse	gases	(GHGs)	have	the	potential	to	

adversely	affect	the	environment	in	a	cumulative	context.		The	emissions	from	a	single	project	will	

not	cause	global	climate	change,	however,	GHG	emissions	from	multiple	projects	throughout	the	

world	could	 result	in	a	cumulative	impact	with	 respect	 to	global	climate	change.		Therefore,	 the	

analysis	 of	 GHGs	 and	 climate	 change	 presented	 in	 this	 section	 is	 presented	 in	 terms	 of	 the	

proposed	 project’s	 cumulative	 contribution	 and	 potential	 to	 result	 in	 cumulatively	 considerable	

impacts	related	to	GHGs	and	climate	change.		

Cumulative	impacts	are	 the	 collective	impacts	 of	 one	 or	more	 past,	 present,	and	 future	 projects	

that,	 when	 combined,	 result	 in	 adverse	 changes	 to	 the	 environment.	 In	 determining	 the	

significance	of	a	proposed	project’s	contribution	 to	anticipated	adverse	 future	conditions,	a	lead	

agency	should	generally	undertake	a	two-step	analysis.	The	first	question	is	whether	the	combined	

effects	from	both	the	proposed	project	and	other	projects	would	be	cumulatively	significant.	If	the	

agency	 answers	 this	 inquiry	 in	 the	 affirmative,	 the	 second	 question	 is	 whether	 “the	 proposed	

project’s	 incremental	 effects	 are	 cumulatively	 considerable”	 and	 thus	 significant	 in	 and	 of	

themselves.	 The	 cumulative	 project	 list	 for	 this	 issue	 (climate	 change)	 comprises	 anthropogenic	

(i.e.,	 human-made)	 GHG	 emissions	 sources	 across	 the	 globe,	 and	 no	 project	 alone	 would	

reasonably	 be	 expected	 to	 contribute	 to	 a	 noticeable	 incremental	 change	 to	 the	 global	 climate.	

However,	 legislation	 and	 executive	 orders	 on	 the	 subject	 of	 climate	 change	 in	 California	 have	

established	a	statewide	context	for	and	a	process	for	developing	an	enforceable	statewide	cap	on	

GHG	emissions.	Given	 the	nature	of	environmental	consequences	 from	GHGs	and	global	climate	

change,	 CEQA	 requires	 that	 lead	 agencies	 consider	 evaluating	 the	 cumulative	 impacts	 of	 GHGs,	

even	 relatively	 small	 (on	 a	 global	 basis)	 additions.	 Small	 contributions	 to	 this	 cumulative	 impact	

(from	 which	 significant	 effects	 are	 occurring	 and	 are	 expected	 to	 worsen	 over	 time)	 may	 be	

potentially	considerable	and	therefore	significant.

2.1 ENVIRONMENTAL	SETTING

GREENHOUSE	GASES	AND	CLIMATE	CHANGE	LINKAGES

Various	gases	in	the	Earth’s	atmosphere,	classified	as	atmospheric	greenhouse	gases	(GHGs),	play	

a	 critical	 role	 in	 determining	 the	 Earth’s	 surface	 temperature.	 Solar	 radiation	 enters	 Earth’s	

atmosphere	 from	 space,	 and	 a	 portion	 of	 the	 radiation	 is	 absorbed	 by	 the	 Earth’s	 surface.	 The	

Earth	emits	this	radiation	back	toward	space,	but	the	properties	of	the	radiation	change	from	highfrequency	solar	radiation	to	lower-frequency	infrared	radiation.		
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Naturally	 occurring	greenhouse	gases	include	water	 vapor	 (H2O),	 carbon	 dioxide	 (CO2),	methane	

(CH4),	nitrous	oxide	(N2O),	and	ozone	(O3).		Several	classes	of	halogenated	substances	that	contain	

fluorine,	chlorine,	or	bromine	are	also	greenhouse	gases,	but	they	are,	for	the	most	part,	solely	a	

product	 of	 industrial	 activities.	 	 Although	 the	 direct	 greenhouse	 gases	 CO2,	 CH4,	 and	 N2O	 occur	

naturally	 in	 the	 atmosphere,	 human	 activities	 have	 changed	 their	 atmospheric	 concentrations.		

From	 the	 pre-industrial	 era	 (i.e.,	 ending	 about	 1750)	 to	 2005,	 concentrations	 of	 these	 three	

greenhouse	gases	have	increased	globally	by	36,	148,	and	18	percent,	respectively	(IPCC	2007)1.

Greenhouse	 gases,	 which	 are	 transparent	 to	 solar	 radiation,	 are	 effective	 in	 absorbing	 infrared	

radiation.	 As	 a	 result,	 this	 radiation	 that	 otherwise	 would	 have	 escaped	 back	 into	 space	 is	 now	

retained,	resulting	in	a	warming	of	the	atmosphere.	This	phenomenon	is	known	as	the	greenhouse	

effect.	 Among	 the	 prominent	 GHGs	 contributing	 to	 the	 greenhouse	 effect	 are	 carbon	 dioxide	

(CO2),	 methane	 (CH4),	 ozone	 (O3),	 water	 vapor,	 nitrous	 oxide	 (N2O),	 and	 chlorofluorocarbons	

(CFCs).

Emissions	of	GHGs	contributing	 to	global	climate	change	are	attributable	in	large	part	 to	human	

activities	 associated	 with	 the	 industrial/manufacturing,	 utility,	 transportation,	 residential,	 and	

agricultural	sectors	(California	Energy	Commission	2006a) 2.	In	California,	the	transportation	sector	

is	 the	 largest	 emitter	 of	 GHGs,	 followed	 by	 electricity	 generation	 (California	 Energy	 Commission	

2006a).	

As	the	name	implies,	global	climate	change	is	a	global	problem.	GHGs	are	global	pollutants,	unlike	

criteria	 air	 pollutants	 and	 toxic	 air	 contaminants,	 which	 are	 pollutants	 of	 regional	 and	 local	

concern,	 respectively.	 California	 produced	 492	 million	 gross	 metric	 tons	 of	 carbon	 dioxide	

equivalents	 (MMTCO2e)	 in	 2004	 (California	 Energy	 Commission	 2006a).	 By	 2020,	 California	 is	

projected	to	produce	507	MMTCO2e	per	year.

3

Carbon	dioxide	equivalents	are	a	measurement	used	 to	account	 for	 the	 fact	 that	different	GHGs	

have	 different	 potential	 to	 retain	 infrared	 radiation	 in	 the	 atmosphere	 and	 contribute	 to	 the	

greenhouse	 effect.	 This	 potential,	 known	 as	 the	 global	 warming	 potential	 of	 a	 GHG,	 is	 also	

dependent	on	the	lifetime,	or	persistence,	of	the	gas	molecule	in	the	atmosphere.	Expressing	GHG	

																																																												

1 Intergovernmental	Panel	on	Climate	Change.	2007.	“Climate	Change	2007:	The	Physical	Science	Basis,	

Summary	for	Policymakers.”

http://www.ipcc.ch/publications_and_data/publications_ipcc_fourth_assessment_report_wg1_report_the_

physical_science_basis.htm

2 California	Energy	Commission.	2006a.	Inventory	of	California	Greenhouse	Gas	Emissions	and	Sinks	1990	to	

2004.		http://www.arb.ca.gov/cc/inventory/archive/archive.htm

3

	California	Air	Resources	Board.	2010.	“Functional	Equivalent	Document	prepared	for	the	California	Cap	on	

GHG	Emissions	and	Market-Based	Compliance	Mechanisms.”	
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emissions	 in	 carbon	 dioxide	 equivalents	 takes	 the	 contribution	 of	 all	 GHG	 emissions	 to	 the	

greenhouse	effect	and	converts	them	to	a	single	unit	equivalent	to	the	effect	that	would	occur	if	

only	CO2	were	being	emitted.	

Consumption	of	fossil	fuels	in	the	transportation	sector	was	the	single	largest	source	of	California’s	

GHG	emissions	in	2004,	accounting	for	40.7%	of	total	GHG	emissions	in	the	state	(California	Energy	

Commission	 2006a).	 This	 category	 was	 followed	 by	 the	electric	 power	 sector	 (including	 both	 instate	 and	 out	 of-state	 sources)	 (22.2%)	 and	 the	 industrial	 sector	 (20.5%)	 (California	 Energy	

Commission	2006a).

EFFECTS	OF	GLOBAL	CLIMATE	CHANGE

The	effects	of	increasing	global	 temperature	are	 far-reaching	and	extremely	difficult	 to	quantify.		

The	 scientific	 community	 continues	 to	 study	 the	 effects	 of	 global	 climate	 change.	 	 In	 general,	

increases	in	the	ambient	global	temperature	as	a	result	of	increased	GHGs	are	anticipated	to	result	

in	rising	sea	levels,	which	could	threaten	coastal	areas	through	accelerated	coastal	erosion,	threats	

to	levees	and	inland	water	systems	and	disruption	to	coastal	wetlands	and	habitat.			

If	 the	 temperature	 of	 the	 ocean	 warms,	 it	 is	 anticipated	 that	 the	 winter	 snow	 season	 would	 be	

shortened.	Snowpack	in	the	Sierra	Nevada	provides	both	water	supply	(runoff)	and	storage	(within	

the	 snowpack	 before	 melting),	 which	 is	 a	 major	 source	 of	 supply	 for	 the	 state.	 The	snowpack	

portion	of	the	supply	could	potentially	decline	by	70%	to	90%	by	the	end	of	the	21st	century	(Cal	

EPA	 2006)4.	 This	 phenomenon	 could	 lead	 to	 significant	 challenges	 securing	 an	 adequate	 water	

supply	 for	a	growing	 state	 population.	 Further,	 the	 increased	 ocean	 temperature	 could	 result	 in	

increased	moisture	 flux	 into	 the	 state;	 however,	 since	 this	would	 likely	 increasingly	 come	 in	 the	

form	 of	 rain	 rather	 than	 snow	 in	 the	 high	 elevations,	 increased	 precipitation	 could	 lead	 to	

increased	potential	and	severity	of	flood	events,	placing	more	pressure	on	California’s	levee/flood	

control	system.	

Sea	level	has	risen	approximately	seven	inches	during	the	last	century	and	it	is	predicted	to	rise	an	

additional	22	to	35	inches	by	2100,	depending	on	the	future	GHG	emissions	levels	(Cal	EPA	2006).	

If	 this	 occurs,	 resultant	 effects	 could	 include	 increased	 coastal	 flooding,	 saltwater	 intrusion	 and	

disruption	of	wetlands	(Cal	EPA	2006).	As	the	existing	climate	throughout	California	changes	over	

time,	 mass	 migration	 of	 species,	 or	 failure	 of	 species	 to	 migrate	 in	 time	 to	 adapt	 to	 the	

perturbations	in	climate,	could	also	result.	Under	the	emissions	scenarios	of	the	Climate	Scenarios	

report	 (Cal	EPA	2006),	the	impacts	of	global	warming	in	California	are	anticipated	to	include,	but	

are	not	limited	to,	the	following.	

																																																												

4 California	Environmental	Protection	Agency,	Climate	Action	Team.	2006.	Climate	Action	Team	Report	to	

Governor	Schwarzenegger	and	the	Legislature.

http://www.climatechange.ca.gov/climate_action_team/reports/
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PUBLIC	HEALTH	

Higher	temperatures	are	expected	to	increase	the	frequency,	duration,	and	intensity	of	conditions	

conducive	 to	 air	 pollution	 formation.	 For	 example,	 days	 with	 weather	 conducive	 to	 ozone	

formation	are	projected	to	increase	from	25%	to	35%	under	the	lower	warming	range	and	to	75%	

to	85%	under	the	medium	warming	range.	In	addition,	if	global	background	ozone	levels	increase	

as	predicted	in	some	scenarios,	it	may	become	impossible	to	meet	local	air	quality	standards.	Air	

quality	could	be	further	compromised	by	increases	in	wildfires,	which	emit	fine	particulate	matter	

that	 can	 travel	 long	 distances	 depending	 on	 wind	 conditions.	 The	 Climate	 Scenarios	 report	

indicates	 that	 large	 wildfires	 could	 become	 up	 to	 55%	 more	 frequent	 if	 GHG	 emissions	 are	 not	

significantly	reduced.	

In	addition,	under	the	higher	warming	scenario,	there	could	be	up	to	100	more	days	per	year	with	

temperatures	above	90oF	in	Los	Angeles	and	95oF	in	Sacramento	by	2100.	This	is	a	large	increase	

over	 historical	 patterns	 and	 approximately	 twice	 the	 increase	 projected	 if	 temperatures	 remain	

within	or	below	the	lower	warming	range.	Rising	temperatures	will	increase	the	risk	of	death	from	

dehydration,	 heat	 stroke/exhaustion,	 heart	 attack,	 stroke,	 and	 respiratory	 distress	 caused	 by	

extreme	heat.	

WATER	RESOURCES	

A	 vast	 network	 of	man-made	 reservoirs	and	aqueducts	 capture	and	 transport	water	 throughout	

the	state	 from	northern	California	 rivers	and	 the	Colorado	River.	The	current	distribution	system	

relies	 on	 Sierra	 Nevada	 snow	 pack	 to	 supply	 water	 during	 the	 dry	 spring	 and	 summer	 months.	

Rising	temperatures,	potentially	compounded	by	decreases	in	precipitation,	could	severely	reduce	

spring	snow	pack,	increasing	the	risk	of	summer	water	shortages.	

The	 state’s	 water	 supplies	 are	 also	 at	 risk	 from	 rising	 sea	 levels.	 An	 influx	 of	 saltwater	 would	

degrade	California’s	estuaries,	wetlands,	and	groundwater	aquifers.	Saltwater	intrusion	caused	by	

rising	sea	levels	is	a	major	threat	to	the	quality	and	reliability	of	water	within	the	southern	edge	of	

the	Sacramento/San	Joaquin	River	Delta,	a	major	state	fresh	water	supply.	Global	warming	is	also	

projected	to	seriously	affect	agricultural	areas,	with	California	farmers	projected	to	lose	as	much	as	

25%	of	the	water	supply	they	need;	decrease	the	potential	for	hydropower	production	within	the	

state	 (although	 the	 effects	 on	 hydropower	 are	 uncertain);	 and	 seriously	 harm	 winter	 tourism.	

Under	 the	 lower	 warming	 range,	 the	 snow	 dependent	 winter	 recreational	 season	 at	 lower	

elevations	could	be	reduced	by	as	much	as	one	month.	If	temperatures	reach	the	higher	warming	

range	 and	 precipitation	 declines,	 there	 might	 be	 many	 years	 with	 insufficient	 snow	 for	 skiing,	

snowboarding,	and	other	snow	dependent	recreational	activities.	

If	GHG	emissions	continue	unabated,	more	precipitation	will	 fall	as	rain	instead	of	snow,	and	the	

snow	that	does	 fall	will	melt	earlier,	reducing	the	Sierra	Nevada	spring	snow	pack	by	as	much	as	

70%	to	90%.	Under	the	lower	warming	scenario,	snow	pack	losses	are	expected	to	be	only	half	as	

large	 as	 those	 expected	 if	 temperatures	 were	 to	 rise	 to	 the	 higher	 warming	 range.	 How	 much	

snow	pack	will	be	lost	depends	in	part	on	future	precipitation	patterns,	the	projections	for	which	

remain	 uncertain.	 However,	 even	 under	 the	 wetter	 climate	 projections,	 the	 loss	 of	 snow	 pack	
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would	pose	challenges	to	water	managers,	hamper	hydropower	generation,	and	nearly	eliminate	

all	skiing	and	other	snow-related	recreational	activities.	

AGRICULTURE	

Increased	GHG	 emissions	 are	 expected	 to	 cause	 widespread	 changes	 to	 the	 agriculture	 industry	

reducing	 the	 quantity	 and	 quality	 of	 agricultural	 products	 statewide.	 Although	 higher	 carbon	

dioxide	levels	can	stimulate	plant	production	and	increase	plant	water-use	efficiency,	California’s	

farmers	will	face	greater	water	demand	for	crops	and	a	less	reliable	water	supply	as	temperatures	

rise.

Plant	growth	 tends	 to	 be	 slow	at	low	 temperatures,	increasing	with	 rising	 temperatures	 up	 to	a	

threshold.	However,	faster	growth	can	result	in	less-than-optimal	development	for	many	crops,	so	

rising	 temperatures	 are	 likely	 to	 worsen	 the	 quantity	 and	 quality	 of	 yield	 for	 a	 number	 of	

California’s	 agricultural	 products.	 Products	 likely	 to	 be	most	 affected	 include	 wine	 grapes,	 fruits	

and	nuts,	and	milk.	

Crop	 growth	 and	 development	 will	 be	 affected,	 as	 will	 the	 intensity	 and	 frequency	 of	 pest	 and	

disease	outbreaks.	Rising	 temperatures	will	likely	aggravate	ozone	pollution,	which	makes	plants	

more	susceptible	to	disease	and	pests	and	interferes	with	plant	growth.

In	 addition,	 continued	 global	 warming	 will	 likely	 shift	 the	 ranges	 of	 existing	 invasive	 plants	 and	

weeds	 and	 alter	 competition	 patterns	 with	 native	 plants.	 Range	 expansion	 is	 expected	 in	 many	

species	 while	 range	 contractions	 are	 less	 likely	 in	 rapidly	 evolving	 species	 with	 significant	

populations	already	established.	Should	range	contractions	occur,	it	is	likely	that	new	or	different	

weed	 species	 will	 fill	 the	 emerging	 gaps.	 Continued	 global	 warming	 is	 also	 likely	 to	 alter	 the	

abundance	 and	 types	 of	 many	 pests,	 lengthen	 pests’	 breeding	 season,	 and	 increase	 pathogen	

growth	rates.	

FORESTS	AND	LANDSCAPES	

Global	warming	is	expected	 to	alter	 the	distribution	and	character	of	natural	vegetation	 thereby	

resulting	 in	 a	 possible	 increased	 risk	 of	 large	 of	 wildfires.	 If	 temperatures	 rise	 into	 the	 medium	

warming	range,	the	risk	of	large	wildfires	in	California	could	increase	by	as	much	as	55%,	which	is	

almost	 twice	 the	 increase	 expected	 if	 temperatures	 stay	 in	 the	 lower	 warming	 range.	 However,	

since	 wildfire	 risk	 is	 determined	 by	 a	 combination	 of	 factors,	 including	 precipitation,	 winds,	

temperature,	and	landscape	and	vegetation	conditions,	future	risks	will	not	be	uniform	throughout	

the	 state.	 For	 example,	 if	 precipitation	 increases	 as	 temperatures	 rise,	 wildfires	 in	 southern	

California	 are	 expected	 to	 increase	 by	 approximately	 30%	 toward	 the	 end	 of	 the	 century.	 In	

contrast,	precipitation	decreases	could	increase	wildfires	in	northern	California	by	up	to	90%.	

Moreover,	continued	global	warming	will	alter	natural	ecosystems	and	biological	diversity	within	

the	state.	For	example,	alpine	and	sub-alpine	ecosystems	are	expected	 to	decline	by	as	much	as	

60%	to	80%	by	the	end	of	the	century	as	a	result	of	increasing	temperatures.	The	productivity	of	

the	state’s	forests	is	also	expected	to	decrease	as	a	result	of	global	warming.	
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RISING	SEA	LEVELS	

Rising	 sea	levels,	more	intense	 coastal	 storms,	and	warmer	water	 temperatures	will	increasingly	

threaten	the	state’s	coastal	regions.	Under	the	higher	warming	scenario,	sea	level	is	anticipated	to	

rise	 22	 to	 35	 inches	 by	 2100.	 Elevations	 of	 this	 magnitude	 would	 inundate	 coastal	 areas	 with	

saltwater,	accelerate	coastal	erosion,	threaten	vital	levees	and	inland	water	systems,	and	disrupt	

wetlands	and	natural	habitats.	

2.2 REGULATORY	SETTING

FEDERAL	

The	Environmental	Protection	Agency	(EPA)	is	the	federal	agency	responsible	for	implementing	the	

Clean	Air	Act	(CAA).	The	Supreme	Court	of	the	United	States	ruled	on	April	2,	2007	that	CO2	is	an	

air	 pollutant	as	 defined	 under	 the	 CAA,	and	 that	EPA	 has	 the	authority	 to	 regulate	emissions	 of	

GHGs.	 In	 response	 to	 the	 mounting	 issue	 of	 climate	 change,	 EPA	 has	 taken	 actions	 to	 regulate,	

monitor,	and	potentially	reduce	GHG	emissions.

GREENHOUSE	GAS	PERMITTING	REQUIREMENTS	ON	LARGE	INDUSTRIAL	FACILITIES

On	May	13,	2010,	EPA	issued	 the	Prevention	of	Significant	Deterioration	and	Title	V	Greenhouse

Gas	 Tailor	 Rule.	 This	 final	 rule	 sets	 thresholds	 for	 greenhouse	 gas	 (GHG)	 emissions	 that	 define	

when	permits	under	the	New	Source	Review	Prevention	of	Significant	Deterioration	(PSD)	and	Title	

V	Operating	Permit	programs	are	required	for	new	and	existing	industrial	facilities.	

The	rule	establishes	a	schedule	that	will	initially	focus	permitting	programs	on	the	largest	sources	

and	then	expands	beyond	certain	permitting	programs	to	cover	the	largest	sources	of	GHGs	that	

may	 not	 have	 been	 previously	 covered	 by	 the	 CAA	 for	 other	 pollutants.	 During	 Step	 1,	 from	

January	 2,	 2011	 to	 June	 30,	 2011,	 only	 sources	 currently	 subject	 to	 the	 PSD	 permitting	 program	

(i.e.,	those	that	are	newly-constructed	or	modified	in	a	way	that	significantly	increases	emissions	

of	 a	 pollutant	 other	 than	 GHGs)	 would	 be	 subject	 to	 permitting	 requirements	 for	 their	 GHG	

emissions	under	PSD;	and,	for	these	projects,	only	GHG	increases	of	75,000	tons	(68,039	MT)	per	

year	 or	more,	 on	 a	 CO2e	 basis,	 would	 need	 to	 determine	 the	 Best	 Available	 Control	Technology	

(BACT)	for	their	GHG	emissions.	Similarly	for	the	operating	permit	program,	only	sources	currently	

subject	to	the	program	(i.e.,	newly	constructed	or	existing	major	sources	for	a	pollutant	other	than	

GHGs)	would	be	subject	 to	Title	V	 requirements	 for	GHG.	During	 this	 time,	no	sources	would	be	

subject	to	Clean	Air	Act	permitting	requirements	due	solely	to	GHG	emissions.

Step	 2	 will	 build	 on	 Step	 1.	 During	 Step	 2,	 from	 July	 1,	 2011	 to	 June	 30,	 2013,	 PSD	 permitting	

requirements	will	cover	for	the	first	time	new	construction	projects	that	emit	GHG	emissions	of	at	

least	100,000	tons	(90,718	MT)	per	year	even	if	they	do	not	exceed	the	permitting	thresholds	for	

any	 other	 pollutant.	 Modifications	 at	 existing	 facilities	 that	 increase	 GHG	 emissions	 by	 at	 least	

75,000	tons	(68,039	MT)	per	year	will	be	subject	to	permitting	requirements,	even	if	they	do	not	

significantly	increase	emissions	 of	any	 other	 pollutant.	In	Step	 2,	 operating	 permit	 requirements	

will,	for	the	first	time,	apply	to	sources	based	on	their	GHG	emissions	even	if	they	would	not	apply	

based	on	emissions	of	any	other	pollutant.	Facilities	 that	emit	at	least	100,000	 tons	 (90,718	MT)	

per	year	of	CO2e	will	be	subject	to	Title	V	permitting	requirements.
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As	 part	 of	 this	 rule,	 EPA	 also	 commits	 to	 undertake	 another	 rulemaking,	 to	 begin	 in	 2011	 and	

conclude	no	later	than	July	1,	2012.	That	action	will	consist	of	an	additional	Step	3	for	phasing	in	

GHG	permitting.	Step	three,	if	established,	will	not	require	permitting	for	sources	with	greenhouse	

gas	emissions	below	50,000	tons	(45,359	MT)	per	year.

In	 early	 2011,	 the	 EPA	 granted	 a	 three-year	 exemption	 from	 this	 rule	 for	 large-scale	 biomassburning	facilities.		At	the	time	of	writing	of	this	document,	the	three-year	biomass	exemption	is	in	

effect.	However,	this	EPA	ruling	to	exempt	biomass	has	been	challenged	by	environmental	groups.		

Given	the	uncertainties	related	to	when	the	proposed	project	will	be	constructed	and	operational,	

and	whether	 or	 not	legal	 challenges	 to	 the	EPA’s	 biomass	exemption	will	 be	 successful,	it	is	 not	

known	whether	or	not	the	proposed	Cogen	Facility	will	be	required	to	determine	and	implement	

BACT	for	GHGs	under	the	PSD	program.		

MANDATORY	GREENHOUSE	GAS	REPORTING	RULE

On	September	22,	2009,	EPA	issued	a	final	rule	for	mandatory	reporting	of	GHGs	from	large	GHG	

emissions	sources	in	the	United	States.	In	general,	this	national	reporting	requirement	will	provide	

EPA	with	accurate	and	 timely	GHG	emissions	data	 from	 facilities	 that	emit	25,000	metric	 tons	or	

more	 of	 CO2	 per	 year.	 This	 publically	 available	 data	 will	 allow	 the	 reporters	 to	 track	 their	 own	

emissions,	compare	them	to	similar	facilities,	and	aid	in	identifying	cost	effective	opportunities	to	

reduce	emissions	 in	 the	 future.	 Reporting	 is	 at	 the	 facility	 level,	except	 that	 certain	 suppliers	 of	

fossil	 fuels	 and	 industrial	 greenhouse	 gases	 along	 with	 vehicle	 and	 engine	 manufacturers	 will	

report	 at	 the	 corporate	 level.	 An	 estimated	 85%	 of	 the	 total	 U.S.	 GHG	 emissions,	 from	

approximately	10,000	facilities,	are	covered	by	this	final	rule.		The	proposed	Cogen	Facility	will	be	

subject	to	the	GHG	reporting	requirements	established	by	this	rule.		

ENERGY	POLICY	AND	CONSERVATION	ACT	

The	Energy	Policy	and	Conservation	Act	of	1975	sought	to	ensure	that	all	vehicles	sold	in	the	U.S.	

would	 meet	 certain	 fuel	 economy	 goals.	 Through	 this	 Act,	 Congress	 established	 the	 first	 fuel	

economy	standards	for	on-road	motor	vehicles	in	the	United	States	(U.S.).		Pursuant	to	the	Act,	the	

National	 Highway	 Traffic	 and	 Safety	 Administration,	 which	 is	 part	 of	 the	 U.S.	 Department	 of	

Transportation	 (USDOT),	 is	 responsible	 for	 establishing	 additional	 vehicle	 standards	 and	 for	

revising	existing	standards.	

Since	1990,	the	fuel	economy	standard	for	new	passenger	cars	has	been	27.5	mpg.	Since	1996,	the	

fuel	economy	standard	for	new	light	trucks	(gross	vehicle	weight	of	8,500	pounds	or	less)	has	been

20.7	mpg.	Heavy-duty	vehicles	 (i.e.,	vehicles	and	 trucks	 over	 8,500	 pounds	gross	vehicle	weight)	

are	 not	 currently	 subject	 to	 fuel	 economy	 standards.	 Compliance	 with	 federal	 fuel	 economy	

standards	is	determined	on	the	basis	of	each	manufacturer’s	average	fuel	economy	for	the	portion	

of	its	vehicles	produced	for	sale	in	the	U.S.	The	Corporate	Average	Fuel	Economy	(CAFE)	program,	

which	 is	 administered	 by	 the	 U.S.	 Environmental	 Protection	 Agency	 (EPA),	 was	 created	 to	

determine	 vehicle	 manufacturers’	 compliance	 with	 the	 fuel	 economy	 standards.	 The	 EPA	

calculates	a	CAFE	value	for	each	manufacturer	based	on	city	and	highway	fuel	economy	test	results	

and	 vehicle	 sales.	 Based	 on	 the	 information	 generated	 under	 the	 CAFE	 program,	 the	 USDOT	 is	

authorized	to	assess	penalties	for	noncompliance.	
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ENERGY	POLICY	ACT	OF	1992 (EPACT)

The	Energy	Policy	Act	of	1992	(EPAct)	was	passed	to	reduce	the	country’s	dependence	on	foreign	

petroleum	and	improve	air	quality.	EPAct	includes	several	parts	intended	to	build	an	inventory	of	

alternative	 fuel	 vehicles	 (AFVs)	 in	 large,	 centrally	 fueled	 fleets	 in	 metropolitan	 areas.	 EPAct	

requires	certain	 federal,	state,	and	local	government	and	private	 fleets	to	purchase	a	percentage	

of	 light	 duty	 AFVs	 capable	 of	 running	 on	 alternative	 fuels	 each	 year.	 In	 addition,	 financial	

incentives	 are	 included	 in	 EPAct.	 Federal	 tax	 deductions	 will	 be	 allowed	 for	 businesses	 and	

individuals	to	cover	the	incremental	cost	of	AFVs.	States	are	also	required	by	the	act	to	consider	a	

variety	of	incentive	programs	to	help	promote	AFVs.	

ENERGY	POLICY	ACT	OF	2005

The	Energy	Policy	Act	of	2005	was	signed	into	law	on	August	8,	2005.		Generally,	the	act	provides	

for	renewed	and	expanded	tax	credits	for	electricity	generated	by	qualified	energy	sources,	such	as	

landfill	 gas;	 provides	 bond	 financing,	 tax	 incentives,	 grants,	 and	 loan	 guarantees	 for	 a	 clean	

renewable	 energy	 and	 rural	 community	 electrification;	 and	 establishes	 a	 federal	 purchase	

requirement	for	renewable	energy.		

STATE	

CALIFORNIA	STRATEGY	TO	REDUCE	PETROLEUM DEPENDENCE	(AB 2076)

AB	2076	(Chapter	936,	Statutes	of	2000)	requires	the	CEC	and	the	California	Air	Resources	Board	

(CARB) to	 develop	and	 submit	 to	 the	 Legislature	a	 strategy	 to	 reduce	 petroleum	 dependence	 in	

California.	The	statute	requires	the	strategy	to	include	goals	for	reducing	the	rate	of	growth	in	the	

demand	 for	petroleum	 fuels.	In	addition,	the	strategy	is	required	to	include	recommendations	to	

increase	transportation	energy	efficiency	as	well	as	the	use	of	non-petroleum	fuels	and	advanced	

transportation	 technologies	 including	 alternative	 fuel	 vehicles,	 hybrid	 vehicles,	 and	 high-fuel	

efficiency	vehicles.	

The	strategy,	Reducing	California’s	Petroleum	Dependence,	was	adopted	by	 the	CEC	and	CARB	in	

2003.	The	strategy	recommends	that	California	reduce	inroad	gasoline	and	diesel	fuel	demand	to	

15%	 below	 2003	 demand	 levels	 by	 2020	and	maintain	 that	 level	 for	 the	 foreseeable	 future;	 the	

Governor	and	Legislature	work	to	establish	national	fuel	economy	standards	that	double	the	fuel	

efficiency	of	new	cars,	light	trucks,	and	sport	utility	vehicles	 (SUVs);	and	increase	the	use	of	nonpetroleum	fuels	to	20%	of	on-road	fuel	consumption	by	2020	and	30%	by	2030.	

BIOENERGY	ACTION	PLAN	– EXECUTIVE	ORDER	#S-06-06

Executive	Order	#S-06-06	establishes	targets	for	the	use	and	production	of	biofuels	and	biopower	

and	 directs	 state	 agencies	 to	 work	 together	 to	 advance	 biomass	 programs	 in	 California	 while	

providing	environmental	protection	and	mitigation.	The	executive	order	establishes	the	following	

target	to	increase	the	production	and	use	of	bioenergy,	including	ethanol	and	biodiesel	fuels	made	
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from	 renewable	 resources:	 produce	a	minimum	 of	 20%	 of	its	 biofuels	within	 California	 by	 2010,	

40%	by	2020,	and	75%	by	2050.	The	executive	order	also	calls	for	the	state	to	meet	a	target	for	use	

of	biomass	electricity,	including	biomass	cogeneration	facilities.	

GOVERNOR’S	LOW	CARBON	FUEL	STANDARD	(EXECUTIVE	ORDER	#S-01-07)

Executive	Order	#S-01-07	establishes	a	statewide	goal	to	reduce	the	carbon	intensity	of	California’s	

transportation	 fuels	 by	 at	 least	 10%	 by	 2020	 through	 establishment	 of	 a	 Low	 Carbon	 Fuel	

Standard.	The	Low	Carbon	Fuel	Standard	shall	be	incorporated	into	the	State	Alternative	Fuels	Plan	

required	 by	 AB	 1007	 and	 is	 one	 of	 the	 proposed	 discrete	 early	 action	 GHG	 reduction	measures	

identified	by	CARB	pursuant	to	AB	32.	

SENATE	BILL	97 (SB 97)

Senate	 Bill	 97	 was	 signed	 by	 the	 Governor	 on	 August	 24,	 2007.	 	 This	 bill	 provides	 that	 in	 an	

environmental	 impact	 report,	 negative	 declaration,	 mitigated	 negative	 declaration,	 or	 other	

document	required	by	CEQA	for	either	transportation	projects	funded	under	the	Highway	Safety,	

Traffic	 Reduction,	 Air	Quality	 and	 Port	 Security	 Bond	 Act	 of	 2006,	 or	 projects	 funded	 under	 the	

Disaster	Preparedness	and	Flood	Prevention	Bond	Act	of	2006,	 the	 failure	 to	analyze	adequately	

the	effects	of	greenhouse	gas	emissions	otherwise	required	to	be	reduced	pursuant	to	regulations	

adopted	under	the	Global	Warming	Solutions	Act	of	2006	does	not	create	a	cause	of	action	for	a	

violation	of	CEQA.	The	bill	provides	that	this	provision	shall	apply	retroactively	for	any	of	the	above	

documents	that	are	not	final	and	shall	be	repealed	on	January	1,	2010.	

The	bill	requires	the	Office	of	Planning	and	Research	 (OPR),	by	 July	1,	2009,	to	prepare,	develop,	

and	 transmit	 to	 the	 Resources	 Agency	 guidelines	 for	 the	 feasible	 mitigation	 of	 greenhouse	 gas	

emissions	 or	 the	 effects	 of	 greenhouse	 gas	 emissions,	 as	 required	 by	 CEQA,	 including,	 but	 not	

limited	 to,	effects	associated	with	 transportation	 or	energy	 consumption.	 The	 Resources	Agency	

was	 required	 to	 certify	 and	 adopt	 those	 guidelines	 by	 January	 1,	 2010.	 The	 OPR	 is	 required	 to	

periodically	 update	 the	 guidelines	 to	 incorporate	 new	 information	 or	 criteria	 established	 by	 the	

CARB	pursuant	to	the	California	Global	Warming	Solutions	Act	of	2006.		

CLIMATE	ACTION	PROGRAM	AT	CALTRANS	

In	 December	 2006,	 the	 California	 Department	 of	 Transportation,	 Business,	 Transportation,	 and	

Housing	 Agency,	 issued	 a	 Climate	 Action	 Program.	The	 goal	 of	 the	 Climate	 Action	 Program	 is	 to	

promote	 clean	 and	 energy	 efficient	 transportation,	 and	 provide	 guidance	 for	 mainstreaming	

energy	 and	 climate	 change	 issues	 into	 business	 operations.	 The	 overall	 approach	 to	 lower	 fuel	

consumption	and	CO2	from	transportation	is	twofold:	(1)	reduce	congestion	and	improve	efficiency	

of	 transportation	 systems	 through	 smart	 land	 use,	 operational	 improvements,	 and	 Intelligent	

Transportation	 Systems;	 and	 (2)	 institutionalize	 energy	 efficiency	 and	 GHG	 emission	 reduction	

measures	 and	 technology	 into	 planning,	 project	 development,	 operations,	 and	 maintenance	 of	

transportation	facilities,	fleets,	buildings,	and	equipment.	

The	 reasoning	 underlying	 the	 Climate	 Action	 Program	 is	 the	 conclusion	 that	 “the	most	effective	

approach	to	addressing	GHG	reduction,	in	the	short-to-medium	term,	is	strong	technology	policy	
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and	 market	 mechanisms	 to	 encourage	 innovations.	 Rapid	 development	 and	 availability	 of	

alternative	 fuels	and	vehicles,	increased	efficiency	in	new	cars	and	 trucks	 (light	and	heavy	duty),	

and	 super	 clean	 fuels	 are	 the	 most	 direct	 approach	 to	 reducing	 GHG	 emissions	 from	 motor	

vehicles	(emission	performance	standards	and	fuel	or	carbon	performance	standards).”		

SENATE	BILL	375

SB	 375,	 signed	 in	 September	 2008,	 aligns	 regional	 transportation	 planning	efforts,	 regional	GHG	

emission	 reduction	 targets,	 land	 use,	 and	 housing	 allocation.	 SB	 375	 requires	 Metropolitan	

Planning	Organizations	 (MPOs)	 to	adopt	a	Sustainable	Communities	Strategy	 (SCS)	or	Alternative	

Planning	 Strategy	 (APS),	 which	 will	 prescribe	 land	 use	 allocation	 in	 that	 MPO’s	 Regional	

Transportation	Plan	(RTP).	ARB,	in	consultation	with	MPOs,	will	provide	each	affected	region	with	

reduction	targets	for	GHGs	emitted	by	passenger	cars	and	light	trucks	in	the	region	for	the	years	

2020	and	2035.	These	reduction	targets	will	be	updated	every	8	years,	but	can	be	updated	every	4	

years	 if	 advancements	 in	 emissions	 technologies	 affect	 the	 reduction	 strategies	 to	 achieve	 the	

targets.	 CARB	 is	 also	 charged	 with	 reviewing	 each	 MPO’s	 SCS	 or	 APS	 for	 consistency	 with	 its	

assigned	targets.	If	MPOs	do	not	meet	the	GHG	emission	reduction	targets,	transportation	projects	

would	 not	 be	 eligible	 for	 funding	 programmed	 after	 January	 1,	 2012.	 	 The	 CARB	 assigned	 the	

Shasta	County	Regional	Transportation	Planning	Agency	 (Shasta	RTPA)	with	a	reduction	 target	of	

0%	per	capita	GHG	emissions	from	2005	levels.		

ASSEMBLY	BILL	1493

In	 2002,	 then	Governor	Gray	Davis	 signed	 AB	 1493.	 AB	 1493	 required	 the	 CARB	 to	 develop	 and	

adopt,	 by	 January	 1,	 2005,	 regulations	 that	 achieve	 “the	 maximum	 feasible	 reduction	 of	

greenhouse	 gases	 emitted	 by	 passenger	 vehicles	 and	 light-duty	 truck	 and	 other	 vehicles	

determined	 by	 the	 CARB	 to	 be	 vehicles	 whose	 primary	 use	 is	 noncommercial	 personal	

transportation	in	the	state.”		To	meet	the	requirements	of	AB	1493,	CARB	approved	amendments	

to	the	California	Code	of	Regulations	(CCR)	adding	GHG	emission	standards	to	California’s	existing	

motor	vehicle	emission	standards	in	2004.	

Amendments	to	CCR	Title	13	Sections	1900	(CCR	13	1900)	and	1961	(CCR	13	1961),	and	adoption	

of	Section	1961.1	 (CCR	13	1961.1)	require	automobile	manufacturers	 to	meet	 fleet	average	GHG	

emission	limits	for	all	passenger	cars,	light-duty	trucks	within	various	weight	criteria,	and	mediumduty	 passenger	 vehicle	 weight	 classes	 beginning	 with	 the	 2009	 model	 year.	 Emission	 limits	 are	

further	 reduced	 each	 model	 year	 through	 2016.	 For	 passenger	 cars	 and	 light-duty	 trucks	 3,750	

pounds	or	less	loaded	vehicle	weight	(LVW),	the	2016	GHG	emission	limits	are	approximately	37%	

lower	 than	 the	 during	 the	 first	 year	 of	 the	 regulations	 in	 2009.	 For	 medium-duty	 passenger	

vehicles	 and	 light-duty	 trucks	 3,751	 LVW	 to	 8,500	 pounds	 gross	 vehicle	 weight	 (GVW),	 GHG	

emissions	are	reduced	approximately	24%	between	2009	and	2016.		
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CALIFORNIA	EXECUTIVE	ORDERS	S-3-05	AND	S-20-06,	AND	ASSEMBLY	BILL	32

On	June	1,	2005,	Governor	Arnold	Schwarzenegger	signed	Executive	Order	S-3-05.		The	goal	of	this	

Executive	Order	is	to	reduce	California’s	GHG	emissions	to:		1)	2000	levels	by	2010,	2)	1990	levels	

by	2020	and	3)	80%	below	the	1990	levels	by	2050.		

In	2006,	this	goal	was	further	reinforced	with	the	passage	of	Assembly	Bill	32	(AB	32),	the	Global	

Warming	Solutions	Act	of	2006.		AB	32	sets	the	same	overall	GHG	emissions	reduction	goals	while	

further	mandating	 that	CARB	 create	a	 plan,	which	 includes	market	mechanisms,	and	 implement	

rules	to	achieve	“real,	quantifiable,	cost-effective	reductions	of	greenhouse	gases.”		

Executive	Order	S-20-06	further	directs	state	agencies	to	begin	implementing	AB	32,	including	the	

recommendations	made	by	 the	state’s	Climate	Action	Team	 (CAT).		Each	CAT	working	group	will	

develop	 a	 Near-term	 Implementation	 Plan	 (CATNIPs)	 for	 the	 specific	 climate	 change	 mitigation	

measures	 and	 adaptation	 strategies	 being	 addressed	 by	 the	 working	 group.	 These	 will	 be	 the	

measures	and	strategies	that	will	be	underway	or	completed	by	the	end	of	2010.	The	CATNIP	will	

include	 a	 brief	 description	 of	 the	 measures	 and	 strategies,	 the	 steps	 to	 be	 taken	 in	

implementation,	the	agency/department	responsible,	and	the	timeline	for	completion.	The	Energy	

Working	 Group	 of	 the	 Climate	 Action	 Team	 focuses	 its	 efforts	 on	 both	 greenhouse	 gas	

emission	reduction	and	adaptation	actions	affecting	the	energy	sector.	

CARB,	 which	 is	 part	 of	 Cal-EPA,	 develops	 air	 quality	 regulations	 at	 the	 state	 level.	 	 The	 state	

regulations	 mirror	 federal	 regulations	 by	 establishing	 industry-specific	 pollution	 controls	 for	

criteria,	 toxic,	 and	 nuisance	 pollutants.	 	 California	 also	 requires	 areas	 to	 develop	 plans	 and	

strategies	 for	attaining	state	ambient	air	quality	standards	as	set	 forth	in	 the	California	Clean	Air	

Act	 of	 1988.	 	 In	 addition	 to	 developing	 regulations,	 CARB	 develops	 motor	 vehicle	 emission	

standards	for	California	vehicles.

ASSEMBLY	BILL	32- CLIMATE	CHANGE	SCOPING	PLAN

On	 December	 11,	 2008	 CARB	 adopted	 its	 Climate	 Change	 Scoping	 Plan	 (Scoping	 Plan),	 which	

functions	as	a	roadmap	of	CARB’s	plans	to	achieve	GHG	reductions	in	California	required	by	AB	32	

through	 subsequently	 enacted	 regulations.	 The	 Scoping	 Plan	 contains	 the	 main	 strategies	

California	 will	 implement	 to	 reduce	 CO2e	 emissions	 by	 169	 million	 metric	 tons	 (MMT),	 or	

approximately	30%,	from	the	state’s	projected	2020	emissions	level	of	596	MMT	of	CO2e	under	a	

business-as-usual	scenario.	(This	is	a	reduction	of	42	MMT	CO2e,	or	almost	10%,	from	2002–2004	

average	 emissions,	 but	 requires	 the	 reductions	 in	 the	 face	 of	 population	 and	 economic	 growth	

through	2020.)	The	Scoping	Plan	also	breaks	down	the	amount	of	GHG	emissions	reductions	CARB	

recommends	for	each	emissions	sector	of	the	state’s	GHG	inventory.	

The	Scoping	Plan	calls	for	the	largest	reductions	in	GHG	emissions	to	be	achieved	by	implementing	

the	following	measures	and	standards:

• improved	emissions	standards	 for	light-duty	vehicles	 (estimated	 reductions	of	31.7	MMT	

CO2e),
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• the	Low-Carbon	Fuel	Standard	(15.0	MMT	CO2e),

• energy	efficiency	measures	in	buildings	and	appliances	and	 the	widespread	development	

of	combined	heat	and	power	systems	(26.3	MMT	CO2e),	and

• a	renewable	portfolio	standard	for	electricity	production	(21.3	MMT	CO2e).		

The	Cal-EPA	2011	Greenhouse	Gas	Reduction	Report	Card	 (January,	2011)	reported	that	in	2009,	

the	date	for	which	the	most	current	data	are	available,	California	had	achieved	a	reduction	of	1.3	

MMT	CO2e	compared	to	2007	levels	from	implementation	of	the	RPS	program.		

SENATE	BILL	1368

SB	 1368	 requires	 the	 California	 Energy	 Commission	 (CEC)	 and	 the	 California	 Public	 Utilities	

Commission	(CPUC)	to	set	a	global	warming	emissions	standard	for	electricity	used	in	California	—

regardless	 of	 whether	 it's	 generated	 in-state	 or	 purchased	 from	 plants	 in	 other	 states.	 The	 new	

standard	 applies	 to	 any	 new	 long-term	 financial	 contracts	 for	 base	 load	 electricity,	 and	 applies	

both	 to	 investor-owned	 utilities	 and	 municipal	 utilities.	 	 The	 standard	 for	 baseload	 generation	

owned	 by,	 or	 under	 long-term	 contract	 to	 publicly	 owned	 utilities,	 is	 an	 emissions	 performance	

standard	 (EPS)	of	1,100	lbs	CO2	per	megawatt-hour	 (MWh).		However,	the	CPUC	has	determined	

that	 biomass	 generation	 of	 electricity	 is	 EPS	 compliant	 because	 alternative	 means	 of	 disposing	

biomass	 such	as	 open	air	 burning	and	 landfill	 deposition	 have	 the	 potential	 to	 generate	 greater	

concentrations	 of	 greenhouse	 gas	 in	 the	 atmosphere,	 including	 methane5.	 	 This	 concept	 is	

described	in	greater	detail	later	in	this	EIR	chapter	and	in	the	footnotes	below.		

SENATE	BILLS	1078	AND	107	AND	EXECUTIVE	ORDER	S-14-08

SB	 1078	 (Chapter	 516,	 Statutes	 of	 2002)	 requires	 retail	 sellers	 of	 electricity,	 including	

investor-owned	utilities	and	community	choice	aggregators,	to	provide	at	least	20%	of	their	supply	

from	renewable	sources	by	2017.	SB	107	(Chapter	464,	Statutes	of	2006)	changed	the	target	date	

																																																												

5

	Interim	Opinion	on	Phase	I	Issues:	Greenhouse	Gas	Emissions	Performance	Standard.		CPUC	Decision	07-

01-039	January	25,	2007.		Specifically,	Section	1.6	states:	“In	particular,	the	record	shows	that	electric	

generation	using	biomass	(e.g.,	agricultural	and	wood	waste,	landfill	gas)	that	would	otherwise	be	disposed	

of	under	a	variety	of	conventional	methods	(such	as	open	burning,	forest	accumulation,	landfills,	composting)	

results	in	a	substantial	net	reduction (emphasis	in	original)	in	GHG	emissions.	This	is	because	the	usual	

disposal	options	for	biomass	wastes	emit	large	quantities	of	methane	gas,	whereas	the	energy	alternatives	

either	burn	the	wastes	that	would	become	methane	or	burn	the	methane	itself,	generating	CO2.	Since	

methane	gas	is	on	the	order	of	twenty	to	twenty-five	times	more	potent	as	a	GHG	than	CO2,	and	since	

methane	has	an	atmospheric	residence	time	of	twelve	years,	after	which	it	is	converted	to	atmospheric	CO2,	

trading	off	methane	for	CO2	emissions	from	energy	recovery	operations	leads	to	a	net	reduction	of	the	

greenhouse	effect.”
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to	 2010.	 In	 November	 2008,	 Governor	 Schwarzenegger	 signed	 Executive	 Order	 S-14-08,	 which	

expands	the	state's	Renewable	Energy	Standard	to	33%	renewable	power	by	2020.

CALIFORNIA	RENEWABLES	PORTFOLIO	STANDARD	(RPS)

Established	 in	 2002	 under	 Senate	 Bill	 1078	 and	 accelerated	 in	 2006	 under	 Senate	 Bill	 107,	

California's	Renewables	 Portfolio	Standard	 (RPS)	is	one	of	 the	most	ambitious	 renewable	energy	

standards	in	the	country.	The	RPS	program	requires	electric	corporations	to	increase	procurement	

from	eligible	 renewable	energy	 resources	 by	at	 least	 1%	 of	 their	 retail	 sales	annually,	 until	 they	

reach	 20%	 by	 2010.	 	 Biomass	 generated	 electricity	 is	 considered	 an	 eligible	 renewable	 energy	

source	for	the	RPS	program.	

GHG CAP	AND	TRADE	PROGRAM

California’s	 greenhouse	 gas	 cap	 and	 trade	 program	 is	 a	 central	 element	 of	 California's	 Global	

Warming	Solutions	Act	 (AB	 32)	and	 covers	major	 sources	 of	GHG	emissions	in	 the	State	 such	as	

refineries,	power	plants,	industrial	 facilities,	and	 transportation	 fuels.	 The	 regulation	includes	an	

enforceable	GHG	cap	 that	will	decline	over	 time. 	The	CARB	will	distribute	allowances,	which	are	

tradable	permits,	equal	to	the	emission	allowed	under	the	cap.		The	final	cap	and	trade	regulations	

were	adopted	on	October	20,	2011.		

The	 regulation	 sets	 a	 statewide	 limit	 on	 sources	 responsible	 for	 85	 percent	 of	 California’s	

greenhouse	gas	emissions	and	establishes	a	price	signal	needed	to	drive	long-term	investment	in	

cleaner	 fuels	 and	 more	 efficient	 use	 of	 energy. 	 The	 program	 is	 designed	 to	 provide	 covered	

entities	 the	 flexibility	 to	 seek	 out	 and	 implement	 the	 lowest-cost	 options	 to	 reduce	 emissions.	

The	regulation	will	cover	360	businesses	representing	600	facilities	and	is	divided	into	two	phases:	

the	first,	beginning	in	2013,	will	include	all	major	industrial	sources	along	with	electricity	utilities;	

the	 second,	 starting	in	 2015,	 brings	in	 distributors	 of	 transportation	 fuels,	 natural	gas	and	 other	

fuels.	

Companies	 are	 not	 given	 a	 specific	 limit	 on	 their	 greenhouse	 gas	 emissions	 but	 must	 supply	 a	

sufficient	number	of	allowances	(each	the	equivalent	of	one	ton	of	carbon	dioxide)	to	cover	their	

annual	 emissions. 	 As	 the	 cap	 declines	 each	 year,	 the	 total	 number	 of	 allowances	 issued	 in	 the	

state	 drops,	 requiring	 companies	 to	 find	 the	 most	 cost-effective	 and	 efficient	 approaches	 to	

reducing	 their	 emissions. 	 The	 first	 compliance	 year	 when	 covered	 sources	 will	 have	 to	 turn	 in	

allowances	is	2013.	

To	 ensure	 a	 gradual	 transition,	 CARB	 will	 provide	 the	 majority	 of	 allowances	 to	 all	 industrial	

sources	 during	 the	initial	 period	 (2013-2014),	 using	a	calculation	 that	 rewards	 the	most	efficient	

companies.	Those	that	need	additional	allowances	to	cover	their	emissions	can	purchase	them	at	

regular	 quarterly	 auctions	 CARB	 will	 conduct,	 or	 buy	 them	 on	 the	 market.	 The	 first	 auctions	 of	

allowances	(for	2013	allowances)	are	slated	for	August	and	November	2012.
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Electric	 utilities	 will	 also	 be	 given	 allowances	 to	 be	 sold	 at	 auction	 for	 the	 benefit	 of	 their	

ratepayers	and	to	help	achieve	AB	32	goals.	

The	final	regulations	for	the	cap	and	trade	program	are	codified	in	Subchapter	10	Climate	Change,	

Article	5,	Sections	95800	to	96023,	Title	17,	California	Code	of	Regulations.		Section	95802(a)(31)	

contains	a	definition	of	“biomass”	as	defined	in	 the	cap	and	 trade	 regulations.		 “Biomass	means	

non-fossilized	 and	 biodegradable	 organic	 material	 originating	 from	 plants,	 animals,	 and	

microorganisms,	 including	 products,	 by-products,	 residues,	 and	 waste	 from	 agriculture,	 forestry,	

and	 related	 industries	 as	 well	 as	 the	 non-fossilized	 and	 biodegradable	 organic	 fractions	 of	

industrial	and	municipal	wastes,	including	gases	and	liquids	recovered	 from	 the	decomposition	of	

non-fossilized	and	biodegradable	organic	material.	For	the	purpose	of	this	article,	biomass	includes	

both	California	Renewable	Portfolio	Standard	(RPS)	eligible	and	non-eligible	biomass	as	defined	by	

the	California	Energy	Commission.”

Section	 95852.2	 identifies	 emissions	 without	 a	 compliance	 obligation	 under	 the	 cap	 and	 trade	

program.		As	stated	in	Section	95852.2:	

Emissions	 from	the	 following	source	categories	and	 from	the	combustion	of	the	 following	

fuel	types	count	toward	applicable	reporting	thresholds,	as	applicable	in	MRR	(Mandatory

Reporting	 Regulation),	 but	 do	 not	 count	 toward	 a	 covered	entity’s	 compliance	 obligation	

set	forth	in	this	article	unless	those	emissions	are	reported	as	non-exempt	biomass-	derived	

CO2	under	MRR.	Emissions	without	a	compliance	obligation	include:	

(a)	CO2	emissions	from	combustion	of	the	following	biomass-derived	fuels:	

(1)	The	biogenic	fraction	of	solid	waste	materials	as	reported	under	MRR;	

(2)	Waste	pallets,	crates,	dunnage,	manufacturing	and	construction	wood	

wastes,	 tree	 trimmings,	 mill	 residues,	 and	 range	 land	 maintenance	

residues;	

(3)	All	agricultural	crops	or	waste;	

(4)	 Wood	 and	 wood	 wastes	 identified	 to	 follow	 all	 of	 the	 following	

practices:	

(A)	Harvested	pursuant	 to	an	approved	 timber	management	plan	

prepared	in	accordance	with	the	Z’berg-Nejedly	Forest	Practice	Act	

of	1973	or	other	locally	or	nationally	approved	plan;	and	

(B)	Harvested	for	the	purpose	of	forest	fire	fuel	reduction	or	forest	

stand	improvement.

The	proposed	cogeneration	project	would	utilize	fuel	that	fully	meets	the	definition	of	biomass,	as	

defined	 by	 Title	 17	 California	 Code	 of	 Regulations	 Section	 95802(a)(31).	 	 As	 such,	 per	 the	

requirements	 of	 Section	 95852.2,	 the	 proposed	 project	 would	 be	 required	 to	 report	 GHG	

emissions	 under	 the	Mandatory	 Reporting	 Rule,	 but	GHG	emissions	 from	 the	 project	 would	 not	

count	 towards	 the	 project’s	 compliance	 obligations	 under	 the	 cap	 and	 trade	 program.	 	 In	 other	

words,	 GHG	 emissions	 from	 the	 combustion	 of	 biomass	 fuels	 for	 electricity	 generation	 are	 not	
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required	to	be	offset	or	reduced	under	the	cap	and	trade	program.	The	reason	for	this	exemption	

determination	is	discussed	further	below	in	Section	2.3	and	under	Impact	2.2.

2.3 IMPACTS	AND	MITIGATION	MEASURES

THRESHOLDS	OF	SIGNIFICANCE

As	described	previously,	the	State	Legislature	and	the	global	scientific	community	have	found	that	

global	 climate	 change	 poses	 significant	adverse	effects	 to	 the	environment	 of	 California	and	 the	

entire	world.		

Per	Appendix	G	of	the	CEQA	Guidelines,	climate	change-related	impacts	are	considered	significant	

if	implementation	of	the	proposed	project	under	consideration	would	do	any	of	the	following:

1. Generate	 greenhouse	 gas	 emissions,	 either	 directly	 or	 indirectly,	 that	 may	 have	 a	

significant	impact	on	the	environment.

2. Conflict	with	an	applicable	plan,	policy,	or	regulation	adopted	for	the	purpose	of	reducing	

the	emissions	of	greenhouse	gases.		

Very	few	public	agencies	in	California	have	adopted	GHG	thresholds	of	significance	for	CEQA,	and	

no	GHG	thresholds	have	been	developed	specifically	for	facilities	that	generate	electricity.	Neither	

the	Shasta	County	Air	Quality	Management	District	nor	Shasta	County	has	developed	GHG	CEQA	

thresholds.	

In	order	 to	determine	whether	or	not	 the	proposed	project	would	generate	GHG	emissions	 that	

may	 have	 a	 significant	 impact	 on	 the	 environment,	 Shasta	 County	 has	 relied	 on	 the	 Inclusion	

Thresholds	 for	 Covered	Entities,	as	 described	in	Section	 95812	 of	 the	 Cap	and	Trade	 regulations	

adopted	 by	 CARB	 in	 2011	 (Title	 17,	 California	 Code	 of	 Regulations).	 	 As	 described	 in	 Section	

95812(c)(2),	the	applicability	threshold	for	an	electricity	generating	facility	is	based	on	the	annual	

emissions	 from	 which	 the	 electricity	 originated.	 	 The	 applicability	 threshold	 for	 an	 electricity	

generating	facility	is	25,000	metric	tons	or	more	of	CO2e	per	data	year.		

It	 is	 noted	 and	 acknowledged	 that	 CARB’s	 25,000	 metric	 ton/year	 threshold	 is	 a	 reporting	

threshold	for	the	cap	and	trade	program,	and	was	not	specifically	established	as	a	CEQA	threshold	

for	 GHGs.	 	 However,	 in	 the	 report	 titled:	 CEQA	 and	 Climate	 Change:	 Evaluating	 and	 Addressing	

Greenhouse	Gas	Emissions	 from	 Projects	Subject	 to	 the	California	Environmental	Quality	Act,	 the	

California	 Air	 Pollution	 Control	 Officers	 Association	 (CAPCOA)	 identifies	 the	 25,000	 metric	 ton	

threshold	as	used	by	CARB	 for	their	reporting	threshold,	as	a	potential	and	appropriate	non-zero	

GHG	 threshold	 for	 use	 in	 a	 CEQA	 document	 (see	 pages	 44-45	 of	 the	 above-referenced	 2008	

report).		
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Additionally,	 as	 described	 above,	 the	 U.S.	 EPA	 regulations	 for	 reporting	 of	 greenhouse	 gas	

emissions	 set	a	 25,000	metric	 ton	 threshold	 for	 large	emission	 sources.	 	Through	 its	 rulemaking	

process,	 EPA	 analyzed	 several	 potential	 reporting	 thresholds,	 and	 concluded	 that	 this	 threshold	

would	 “appropriately	 balanc[e]	 emission	 coverage	 and	 burden.”6	 	 EPA	 considered	 but	 rejected	

lower	 thresholds	 of	 1,000	 and	 10,000	 metric	 tons,	 finding	 that	 the	 thresholds	 would	 greatly	

increase	the	number	of	covered	entities	without	capturing	a	significant	additional	portion	of	GHG	

emissions.7	 	 For	 similar	 reasons,	 the	 European	 Union	 has	 provided	 for	 “small	 installations”	 with	

emissions	under	25,000	metric	tons	to	be	exempted	from	its	Emissions	Trading	Scheme;	notably,	

biomass	emissions	are	excluded	from	this	calculation.8

In	 summary,	 a	 25,000	 metric	 ton	 threshold	 has	 been	 determined	 in	 several	 state,	 federal,	 and	

international	 rulemaking	 processes	 to	 represent	 a	 significant	 level	 of	 emissions	 with	 respect	 to	

cumulative	 contributions	 to	 global	 climate	 change.	 	 Given	 the	 extensive	 research	 and	 resources	

that	 went	 into	 the	 development	 of	 the	 GHG	 Mandatory	 Reporting	 Rule	 and	 cap	 and	 trade	

programs	 adopted	 by	 CARB,	 the	 U.S.	 EPA	 greenhouse	 gas	 reporting	 rule,	 and	 the	 fact	 that	 the	

25,000	metric	ton	threshold	would	capture	approximately	94	percent	of	GHG	emissions	associated	

with	stationary	sources	in	California	(CAPCOA	page	44),	Shasta	County	has	determined	that	the	use	

of	the	25,000	metric	tons/year	of	CO2e	threshold	is	the	most	appropriate	quantitative	threshold	to	

apply	 to	 the	 proposed	 project.	 	 This	 numeric	 threshold	 is	 used	 in	 this	 EIR	 to	 determine	 if	 the	

proposed	 project	 would	 have	 a	 significant	 impact,	 or	 result	 in	 a	 cumulatively	 considerable	

contribution,	 to	 climate	 change	 and	 the	 generation	 of	 GHGs.	 	 In	 other	 words,	 if	 the	 proposed	

project	generates	25,000	metric	tons	of	CO2e	or	greater	in	a	year,	it	would	be	considered	to	have	a	

significant	 and	 cumulatively	 considerable	 impact	 on	 the	 environment.	 	 If	 the	 proposed	 project	

would	generate	less	than	25,000	metric	tons	of	CO2e	per	year,	it	would	be	considered	a	less	than	

significant	and	less	than	cumulatively	considerable	impact	related	to	climate	change	and	GHGs.		

In	 order	 to	 determine	 if	 the	 proposed	 project	 would	 conflict	with	 an	 applicable	 plan,	 policy,	 or	

regulation	adopted	for	the	purpose	of	reducing	the	emissions	of	greenhouse	gases,	the	proposed	

project	is	compared	to	the	most	applicable	and	relevant	state-level	regulations	adopted	to	reduce	

GHG	levels.		These	include	regulations	adopted	under	the	AB	32	Scoping	Plan	and	the	Renewables	

Portfolio	Standard	(RPS).

																																																												

6

	74	Fed.	Reg.	56272-73	(Oct.	30,	2009).

7

	Id.	at	56272.

8

	See	Article	27,	European	Parliament	Directive	2003/87/EC,	as	amended	by	Directive	2009/29/EC.
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ANALYSIS	APPROACH

At	the	time	of	preparation	of	this	Recirculated	Draft	EIR,	neither	CARB	nor	the	Shasta	County	Air	

Quality	Management	 District	 has	 formally	 adopted	 a	 recommended	methodology	 for	 evaluating	

GHG	emissions	associated	with	stationary	sources	and/or	new	projects.		

The	California	Office	of	Planning	and	Research	(OPR)	recommends	that	lead	agencies	under	CEQA	

make	 a	 good-faith	 effort,	 based	 on	 available	 information,	 to	 estimate	 the	 quantity	 of	 GHG	

emissions	that	would	be	generated	by	a	proposed	project,	including	the	emissions	associated	with	

construction	activities,	stationary	sources,	vehicular	traffic,	and	energy	consumption:	to	determine	

whether	 the	 impacts	 have	 the	 potential	 to	 result	 in	 a	 significant	 project	 or	 cumulative	

environmental	 impact;	 and,	 where	 feasible	 mitigation	 is	 available,	 to	 mitigate	 any	 project	 or	

cumulative	 impact	 determined	 to	 be	 potentially	 significant.	 	 More	 recently,	 OPR	 prepared	

amendments	to	the	State	CEQA	Guidelines,	pursuant	to	SB	97	 (Statutes	of	2007)	 for	adoption	by	

the	 California	 Natural	 Resources	 Agency.	 The	 amendments	 added	 several	 provisions	 reinforcing	

the	requirements	to	assess	a	project’s	GHG	emissions	as	a	contribution	to	the	cumulative	impact	

of	climate	change.	The	amendments	went	into	effect	on	March	18,	2010.

Specifically,	CEQA	Guidelines	Section	15064.4,	as	amended	March	18,	2010,	state:

(a)	The	determination	of	the	significance	of	greenhouse	gas	emissions	calls	for	a	careful	judgment	

by	 the	lead	agency	consistent	with	 the	provisions	in	section	15064.	A	lead	agency	should	make	a	

good-faith	effort,	based	to	the	extent	possible	on	scientific	and	factual	data,	to	describe,	calculate	

or	estimate	the	amount	of	greenhouse	gas	emissions	resulting	from	a	project.	A	lead	agency	shall	

have	discretion	to	determine,	in	the	context	of	a	particular	project,	whether	to:

(1)	 Use	 a	 model	 or	 methodology	 to	 quantify	 greenhouse	 gas	 emissions	 resulting	 from	 a	

project,	and	which	model	or	methodology	to	use.	The	lead	agency	has	discretion	to	select	

the	model	or	methodology	it	considers	most	appropriate	provided	it	supports	its	decision	

with	substantial	evidence.	The	lead	agency	should	explain	the	limitations	of	the	particular	

model	or	methodology	selected	for	use;	and/or

(2)	Rely	on	a	qualitative	analysis	or	performance	based	standards.

(b)	 A	 lead	 agency	 should	 consider	 the	 following	 factors,	 among	 others,	 when	 assessing	 the	

significance	of	impacts	from	greenhouse	gas	emissions	on	the	environment:

(1)	The	extent	 to	which	 the	 project	may	increase	 or	 reduce	 greenhouse	 gas	emissions	 as	

compared	to	the	existing	environmental	setting;

(2)	Whether	the	project	emissions	exceed	a	threshold	of	significance	that	the	lead	agency	

determines	applies	to	the	project.

(3)	The	extent	to	which	the	project	complies	with	regulations	or	requirements	adopted	to	

implement	 a	 statewide,	 regional,	 or	 local	 plan	 for	 the	 reduction	 or	 mitigation	 of	

greenhouse	 gas	 emissions.	 Such	 requirements	 must	 be	 adopted	 by	 the	 relevant	 public	

agency	 through	 a	 public	 review	 process	 and	 must	 reduce	 or	 mitigate	 the	 project’s	
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incremental	contribution	of	greenhouse	gas	emissions.	If	there	is	substantial	evidence	that	

the	 possible	 effects	 of	 a	 particular	 project	 are	 still	 cumulatively	 considerable	

notwithstanding	compliance	with	the	adopted	regulations	or	requirements,	an	EIR	must	be	

prepared	for	the	project.

Greenhouse	Gases	In	Biomass	Context

Facilities	 fueled	 or	 fired	 by	 biomass	 have	 been	 treated	 as	 “carbon	 neutral”	 by	 national	 and	

international	carbon	 tracking	and	 trading	 systems,	including	 the	 systems	in	use	by	 the	European	

Union,	and	the	Regional	Greenhouse	Gas	Initiative,	which	tracks	greenhouse	gas	emissions	in	the	

northeastern	U.S.

Of	even	greater	relevance	in	the	context	of	this	CEQA	analysis,	is	the	treatment	of	biomass	fueled	

electricity	 facilities	 as	 carbon	 neutral	 by	 the	 California	 Air	 Resources	 Board	 and	 the	 California	

Energy	 Commission.	 	As	 previously	 described	above	 under	 the	 Regulatory	Setting	 section	 of	 this	

EIR	 chapter,	 Section	 95802(a)(31)	 of	 the	 California	 Code	 of	 Regulations	 contains	 a	 definition	 of	

“biomass”	 as	 defined	 in	 the	 cap	 and	 trade	 regulations.	 	 “Biomass	 means	 non-fossilized	 and	

biodegradable	 organic	 material	 originating	 from	 plants,	 animals,	 and	 microorganisms,	 including	

products,	by-products,	residues,	and	waste	from	agriculture,	forestry,	and	related	industries	as	well	

as	 the	 non-fossilized	 and	 biodegradable	 organic	 fractions	 of	 industrial	 and	 municipal	 wastes,	

including	gases	and	liquids	recovered	from	the	decomposition	of	non-fossilized	and	biodegradable	

organic	 material.	 For	 the	 purpose	 of	 this	 article,	 biomass	 includes	 both	 California	 Renewable	

Portfolio	 Standard	 (RPS)	 eligible	 and	 non-eligible	 biomass	 as	 defined	 by	 the	 California	 Energy	

Commission.”

The	entirety	of	the	fuel	mix	proposed	for	the	project	meets	the	definition	of	biomass	fuels	adopted	

in	the	California	Code	of	Regulations.		

Section	 95852.2	 of	 the	 California	 Code	 of	 Regulations	 identifies	emissions	 without	 a	 compliance	

obligation	under	the	cap	and	trade	program.		As	stated	in	Section	95852.2:	

Emissions	 from	the	 following	source	categories	and	 from	the	combustion	of	the	 following	

fuel	types	count	toward	applicable	reporting	thresholds,	as	applicable	in	MRR	(Mandatory	

Reporting	 Regulation),	 but	 do	 not	 count	 toward	 a	 covered	entity’s	 compliance	 obligation	

set	forth	in	this	article	unless	those	emissions	are	reported	as	non-exempt	biomass-	derived	

CO2	under	MRR.	Emissions	without	a	compliance	obligation	include:	

(a)	CO2	emissions	from	combustion	of	the	following	biomass-derived	fuels:	

(1)	The	biogenic	fraction	of	solid	waste	materials	as	reported	under	MRR;	

(2)	Waste	pallets,	crates,	dunnage,	manufacturing	and	construction	wood	

wastes,	 tree	 trimmings,	 mill	 residues,	 and	 range	 land	 maintenance	

residues;	

(3)	All	agricultural	crops	or	waste;	

(4)	 Wood	 and	 wood	 wastes	 identified	 to	 follow	 all	 of	 the	 following	

practices:	
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(A)	Harvested	pursuant	 to	an	approved	 timber	management	plan	

prepared	in	accordance	with	the	Z’berg-Nejedly	Forest	Practice	Act	

of	1973	or	other	locally	or	nationally	approved	plan;	and	

(B)	Harvested	for	the	purpose	of	forest	fire	fuel	reduction	or	forest	

stand	improvement.

By	 exempting	 biomass	 fuels	 from	 the	 compliance	 obligations	 set	 forth	 in	 the	 State’s	 newlyadopted	cap	and	 trade	program,	CARB’s	 regulation	 treats	biomass	 fuels	as	being	carbon	neutral,	

and	should	be	treated	as	such	for	the	purposes	of	GHG	analyses	and	mitigation	programs.		In	order	

to	further	verify	and	clarify	the	treatment	of	biomass	fuels	as	a	carbon	neutral	fuel	source,	CARB	

was	contacted	during	the	preparation	of	this	EIR	to	discuss	CARB’s	treatment	of	biomass	 fuels	in	

the	context	of	carbon	neutrality9.		CARB	staff	verified	 that	biomass	 fuels	are	exempted	 from	 the	

cap	 and	 trade	 program	 because	 they	 are	 considered	 to	 be	 a	 carbon	 neutral	 fuel	 source.	 	 Staff	

further	 verified	 that	 CARB	 treats	 biomass	 fuels	 as	 carbon	 neutral,	 and	 this	 treatment	 was	 the	

foundation	for	the	decision	to	exempt	these	fuel	types	from	the	cap	and	trade	program,10	and	to	

include	electricity	generated	from	biomass	fuels	in	the	RPS	program,	which	is	administered	by	the	

CEC.		CARB	staff	further	stated	that	the	treatment	of	biomass	combustion	as	carbon	neutral	in	the	

context	 of	 this	 EIR	 was	 both	 appropriate,	 and	 consistent	 with	 CARB’s	 treatment	 of	 biomass	

combustion	emissions.		

The	 conventional	 rationale	 for	 conferring	 carbon	 neutrality	 on	 biomass	is	 that	 the	 carbon	in	 the	

biomass,	known	as	biogenic	carbon,	is	already	part	of	the	global	carbon	cycle.		Growth	of	biomass	

removes	 carbon	 from	 the	 atmosphere,	 while	 combustion	 of	 biomass	 returns	 the	 carbon	 to	 the	

atmosphere,	thus	completing	the	loop.11		In	this	regard,	it	is	important	to	consider	both	the	role	of	

forest	management	and	the	treatment	of	biomass	fuels,	as	both	affect	the	overall	GHG	impact.			

																																																												

9

	Mayeur,	Greg.	CARB	Climate	Change	Program	Operations	Sections	Manager.		Personal	communication	

(phone)	with	Ben	Ritchie,	Principal,	De	Novo	Planning	Group.		January	5,	2012.		

10	See,	e.g.,	Final	Statement	of	Reasons	for	California’s	Cap	and	Trade	Program,	October	2011,	at	1188,	

(“biomass-derived	fuels	are	exempt	from	a	compliance	obligation	since	CO2	emissions	resulting	from	the	

combustion	of	biomass	are	considered	biogenic.").	

11	See,	e.g.,	U.S.	Environmental	Protection	Agency,	Inventory	of	U.S.	Greenhouse	Gas	Emissions	and	Sinks,	

1990-2008	(April	15,	2010)	at	3-1	(“It	is	assumed	that	the	carbon	(C)	released	during	the	consumption	of	

biomass	is	recycled	as	U.S.	forests	and	crops	regenerate,	causing	no	net	addition	of	CO2	to	the	

atmosphere.”);	U.S.	Department	of	Agriculture,	Forest	Service	Pacific	Southwest	Research	Station,	Biomass	

to	Energy:	Forest	Management	for	Wildfire	Reduction,	Energy	Production,	and	Other	Benefits,	California	

Energy	Commission	report	no.	CEC-500-2009-080	(January	2010);	Intergovernmental	Panel	on	Climate	

Change,	2006	IPCC	Guidelines	for	National	Greenhouse	Gas	Inventories,	Vol.	1,	General	Guidance	and	

Reporting	(treating	biomass	used	for	energy	production	as	having	zero	emissions	in	the	Energy	Sector);	
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Questions	 have	 been	 raised	 whether	 biomass	 combustion	 should	 be	 considered	 carbon	 neutral	

within	 timeframes	 relevant	 to	 current	 efforts	 to	 mitigate	 the	 impacts	 of	 climate	 change.	 	 In	

accounting	for	the	carbon	budget	of	forest	fuels,	one	may	look	at	the	status	of	the	source	forest	as	

a	 whole,	 on	 a	 landscape	 basis.	 	 If	 total	 biomass	 in	 the	source	 forest	 is	 increasing	 over	 time	 in	

conjunction	with	the	supply	of	forest	removals	to	biomass	power	production,	then	the	enterprise	

is	actually	contributing	to	the	sequestration	of	atmospheric	carbon.12		In	fact,	it	is	well	documented	

that	California	forests	as	a	whole	are	acting	as	a	sink	(net	sequestration)	for	atmospheric	carbon,	

and	that	this	is	a	long-term	trend	that	has	proceeded	in	conjunction	with	past	and	current	levels	of	

forest	harvesting	and	management	in	the	state.13		

Moreover,	in	the	specific	case	of	the	proposed	Cogen	Facility,	it	is	noteworthy	that,	as	described	in	

the	 Project	 Description,	 the	 proposed	 project	 will	 not	 result	 in	 any	 additional	 timber	 harvesting	

operations	 for	 the	 sole	 purpose	 of	 biomass	 combustion.	 	 All	 commercial	 timber	 harvesting	 in	

California	requires	a	Timber	Harvest	Plan	(THP)	that	is	certified,	by	the	Director	of	the	Department	

of	Forestry	and	Fire	Protection,	as	being	in	compliance	with	the	intent	of	the	Z’berg	Nejedly	Forest	

Practice	 Act	 (FPA).	 	 The	 FPA	 requires,	 among	 other	 things,	 that	 a	 THP	 demonstrate	 that	 the	

harvesting	 will	 result	 in	 the	 maximum	 sustained	 production	 of	 high	 quality	 timber	 products.		

Additionally,	power	generation	is	the	lowest-valued	use	for	biomass	resources,	and	only	waste	and	

residual	materials	are	used	as	fuels.

The	 following	 discussion	 addresses	 the	 role	 of	 forest	 management	 practices	 relating	 to	

sequestration	of	carbon.		

Role	of	Forest	Management	in	Carbon	Sequestration

The	proposed	project,	as	described	in	detail	in	the	Project	Description,	does	not	involve	additional	

timber	 harvesting	 or	 changes	 to	 forest	 management.	 	 However,	 the	 following	 discussion	 is	

included	as	background	to	address	the	role	of	forest	management	in	the	analysis	of	the	project’s	

greenhouse	gas	impacts.		CO2	is	consumed	by	growing	trees,	which	release	oxygen	and	store	the	

carbon	 as	 wood	 fiber.	 This	 carbon	 capture	 and	 retention	 through	 photosynthesis	 is	 also	 called	

																																																																																																																																																																																									

Western	Governors’	Association,	Clean	and	Diversified	Energy	Initiative,	Biomass	Task	Force	Report	(January	

2006).

12	This	is	supported	by	 the	IPCC,	which	states:	“In	 the	long	 term,	sustainable	 forest	management	strategy	

aimed	at	maintaining	or	increasing	forest	carbon	stocks,	while	producing	an	annual	yield	of	timber,	fibre,	or	

energy	 from	 the	 forest,	will	generate	the	largest	sustained	mitigation	benefit.”		Nabuurs,	G.J.,	et	al.,	2007:	

Forestry.	In	Climate	Change	2007:	Mitigation.	Contribution	of	Working	Group	III	 to	 the	Fourth	Assessment	

Report	of	the	Intergovernmental	Panel	on	Climate	Change	[B.	Metz	et	al.	(eds)],	Cambridge	University	Press.

13	See	e.g.,	California	Air	Resources	Board,	California’s	1990-2004	Greenhouse	Gas	Emissions	Inventory	and	

1990	Emissions	Level:	Forest	and	Rangeland	Methods	excerpted	from	the	full	Technical	Support	Document,	

May	2009.		
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carbon	sequestration.		Trees	process	CO2	through	photosynthesis,	emit	oxygen	and	store	carbon	in	

the	wood	fiber.	Harvesting	and	replanting	the	temperate	forests	of	North	America,	and	California	

in	particular,	consumes	great	quantities	of	CO2	and	sequesters	the	carbon	in	wood	products	out	of	

the	 atmosphere.	 	 In	 other	 words,	 managing	 temperate	 forests	 in	 North	 America	 creates	 a	

significant	annual	net	GHG	sink.		Generalizing	about	the	effects	of	harvest	is	especially	problematic	

if	 one	 tries	 to	 extrapolate	 from	 studies	 in	 un-managed	 native	 forests	 (sometimes	 called	 old	

growth)	or	extensively	managed	forests	as	compared	to	forests	which	may	have	depleted	carbon	

storage	and	depleted	capacity	for	removal	of	CO2	due	to	past	management.		

To	date,	 the	California	Board	of	Forestry	has	not	promulgated	 rules	 regarding	 the	assessment	of	

GHGs	as	 they	 relate	 to	 timber	operations	or	sustained	 forest	management.		The	Forest	Practices	

Act	and	Forest	Practice	Rules,	 however,	 do	 provide	guidance	 regarding	analysis	of	GHG	impacts.		

These	 include	 the	 requirement	 for	 minimum	 stocking	 standards	 including	 reforestation	

requirements	for	even-aged	management,14	the	requirement	for	large	landowners	to	demonstrate	

Maximum	 Sustained	 Production	 (MSP)	 of	 High	 Quality	 Timber	 Products15	 through	 filing	 and	

approval	 of	 a	 site	 specific,	 ownership-wide,	 State	 reviewed	 document.	 	 In	 addition,	 there	 is	 a	

general	 requirement	 that	 any	 potentially	 significant	 adverse	 cumulative	 effect	 potentially	

emerging	from	a	timber	harvest	plan	be	analyzed.		

The	 regulatory	 underpinning	 for	 GHG	 sequestration	 through	 forest	 management	 is	 the	

demonstration	 of	 MSP.	 	 Laws	 which	 require	 replanting	 of	 harvest	 areas,	 and	 restrictive	 time	

frames	 on	 harvesting	 adjacent	 forest	 stands,	 are	 also	 factors	 ensuring	 future	 tree	 growth.		

Regulatory	 programs	 to	 protect	 wildlife,	 rare	 plants,	 riparian	 function	 with	 streamside	 zones,	

archaeological	 and	 soil	 resources	 may	 inhibit	 the	 ability	 to	 promote,	 to	 the	 maximum	 extent	

possible,	 the	 sequestration	 of	 carbon	 in	 forest	 stands.	 	 The	 reason	 is	 that	 other	 environmental	

values	dictate	that	growth	and	regrowth	be	slowed	or	impeded	as	a	result	of	leaving	trees	that	are	

slow	 growing	 or	 decadent	 and	 therefore	 prevent	 the	 establishment	 of	 younger	 trees	 that	 may	

remove	carbon	at	a	faster	rate.

Again,	the	proposed	project	does	not	change	existing	and	approved	forest	management	practices;	

a	discussion	of	those	practices	is	provided	here	for	informational	background	and	context. For	its	

timberlands,	 SPI’s	 demonstration	 of	 MSP	 shows	 that	 SPI’s	 management	 is	 a	 significant	 sink	 of	

GHGs	over	 the	next	 100	years.		The	SPI	“Option	A”	demonstration	of	MSP	documents	increased	

average	 tree	 diameter	 (Figure	 1),	 increased	 total	 volume	 and	 increased	 sustainable	 harvest	

volumes	 while	 also	 increasing	 the	 habitat	 for	 high	 canopy	 closure	 large	 tree	 dependent	 wildlife	

species	 (Figure	 3).	 	 In	 the	 Option	 A,	 over	 the	 next	 100	 years,	 total	 standing	 inventory	 steadily	

increases	 (almost	 triples)	 and	 sustainable	 harvest	 steadily	 increases	 to	 approximately	 2.5	 times	

current	levels.	(See	Table	A	and	Figure	2	below).

																																																												

14	14	Cal.	Code	Regs.	§	912.7,	932.7,	952.7.

15	14	CCR	§	913.11,	933.11,	953.11.
2012 2.0 GREENHOUSE	GASES	AND	CLIMATE	CHANGE

2.0-22 Second	Recirculated	Draft	EIR	–	SPI	Cogeneration	Power	Project

FIGURE	1 - TREE	DIAMETERS	OVER TIME

SOURCE: SPI’S	 “OPTION	 A DEMONSTRATION	 OF	 MAXIMUM	 SUSTAINABLE	 PRODUCTION	 FOR	 THE	 NORTHERN	 STATE	 FOREST	

DISTRICT,”	ON	FILE	WITH	THE	CALIFORNIA	DEPARTMENT	OF	FORESTRY	& FIRE	PROTECTION	AT	ITS	NORTHERN	DISTRICT	OFFICE (SPI

OPTION	A).
2.0 GREENHOUSE	GASES	AND	CLIMATE	CHANGE 2012

Second	Recirculated	Draft	EIR	–	SPI	Cogeneration	Power	Project 2.0-23

FIGURE	2 – INVENTORY, HARVEST	AND	GROWTH

SOURCE: SPI OPTION	A.

TABLE	A - INVENTORY, HARVEST	AND	GROWTH

SOURCE: SPI OPTION	A.
2012 2.0 GREENHOUSE	GASES	AND	CLIMATE	CHANGE

2.0-24 Second	Recirculated	Draft	EIR	–	SPI	Cogeneration	Power	Project

FIGURE	3 - HABITAT	DISTRIBUTION	CHANGE	OVER TIME

SOURCE: SPI OPTION	A.

Using	 this	 information,	 SPI	 has	 documented	 how	 the	 in-forest	 stock	 of	 carbon	 increases	

significantly	 over	 the	 next	 100	 years.	 	 In	 addition,	 the	 amount	 of	 long-lived	 wood	 products	

produced	annually	also	increases	over	time.	These	products	are	stored	off-site	and	are	subject	to	

less	 risk	 of	 wildfire	 and	 other	events	 that	 could	 quickly	emit	 them	 back	 into	 the	 atmosphere	 as	

CO2.		

A	common	myth	as	applied	 to	 temperate	 forests	is	 that	efforts	 to	reduce	emissions	of	GHGs	are	

served	 better	 by	 leaving	 depleted	 forests	 in	 their	 current	 state	 (i.e.,	 avoidance	 of	 harvesting)	

instead	of	applying	sustainable	forest	management	practices.	In	fact,	forest	management	results	in	

increasing	levels	of	sequestration,	whereas	prevented	management	results	in	either	very	slow	or	

declining	 levels	 of	 sequestration.	 	 Scientific	 literature	 discusses	 how	 sustainable	 forest	

management	 is	 usually	a	 better	 strategy	 for	 controlling	GHG	emissions	 over	 the	 long	 term. 	The	

GHG	benefits	of	sustainable	forest	management	are	associated	with	forest	regrowth	after	harvest;	

lower	 risk	 of	 wildfire;	 production	 of	 energy-efficient	 materials	 and	 biomass	 energy;	 and	 carbon	

sequestration	in	forests	and	wood	products.16 	In	a	recent	report,	the	Intergovernmental	Panel	on	

Climate	Change	concluded	that	“In	the	long	term,	sustainable	forest	management	strategy	aimed	

																																																												

16	Schlamadinger	and	Marland	1996;	Marland	and	Schlamadinger	1997;	Kurz	et	al.	2002.
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Second	Recirculated	Draft	EIR	–	SPI	Cogeneration	Power	Project 2.0-25

at	maintaining	or	increasing	forest	carbon	stocks,	while	producing	an	annual	yield	of	timber,	fibre,	

or	energy	from	the	forest,	will	generate	the	largest	sustained	mitigation	benefit.”17

The	 California	 Air	 Resources	 Board	 and	 the	 California	 Energy	 Commission,	 in	 their	 efforts	 to	

determine	the	GHG	emissions	inventory	for	California	and	for	the	forests	lands	in	California,	have	

determined	 these	 lands	 to	 be	 net	 sequestering	 between	 five	 to 17	 million	 metric	 tons	 of	 CO2

equivalents	annually	(MMTCO2e/year).		A	very	detailed	baseline	analysis	for	forest	GHG	emissions	

and	 sequestration	 from	and	in	 the	 forests	 of	 northern	 California	indicates	 that	 these	 forests	are	

net	of	all	emissions	sequestering	8.76	MMTCO2e/year.18

GHG	Impacts	of	Biomass	Fuel

The	process	of	using	wood	as	a	fuel	source	for	production	of	electricity	and/or	biogenic	fuels,	will	

continue	to	present	a	significant	opportunity	to	improve	atmospheric	GHG	levels.	The	technology	

to	produce	energy	without	adding	net	CO2	to	the	atmosphere	by	burning	fossil	fuels	is	mature	and	

employed	worldwide.		CO2	emissions	from	the	combustion	or	decomposition	of	biogenic	materials	

(e.g.,	paper,	wood	products,	and	trimmings)	grown	on	a	sustainable	basis	are	considered	to	mimic	

the	closed	loop	of	the	natural	carbon	cycle—that	is,	they	return	CO2	to	the	atmosphere	that	was	

originally	 removed	 by	 photosynthesis	 (without	 any	 net	 addition	 to	 the	 total	 carbon	 in	 the	

atmospheric	 carbon	 cycle).19	 	 Thus	 for	 U.S.	 greenhouse	 gas	 inventory	 purposes,	 biogenic	 fuel	

sources	are	not	counted	in	emissions	inventories.		Both	 the	IPCC	and	U.S.	EPA	consider	biomass	

fuels	“carbon	neutral”	as	long	as	the	fuel	source	is	managed	sustainably.		Cogeneration	is	a	process	

by	which	biomass	is	burned	to	make	electricity	while	the	cooling	steam	produced	is	used	to	heat	

and	 dry	 lumber	 (using	 the	 steam	 twice).	 	Using	 cogeneration	 to	 consume	 the	 wood	 fiber	 waste	

material	and	ultimately	remove	and	further	sequester	the	carbon	in	forests	presents	a	substantial	

opportunity	 to	 go	 beyond	 just	 photosynthesis	 (atmospheric	 carbon	 removal	 by	 trees)	 to	 help	

mitigate	the	problem	of	rising	CO2	levels	in	the	atmosphere.

In	California,	 the	designation	of	the	biomass	 fuels	 that	are	used	 for	energy	production	as	carbon	

neutral	is	based	on	a	sophisticated	analysis,	which	tracks	carbon	flows	associated	with	the	biomass	

																																																												

17	IPCC.	2007. 	Climate	Change	2007:	Mitigation.	Contribution	of	Working	Group	III	to	the	Fourth	

Assessment	Report	of	the	Intergovernmental	Panel	on	Climate	Change	[B.	Metz,	O.R.	Davidson,	P.R.	Bosch,	

R.	Dave,	L.A.	Meyer	(eds)],	Cambridge	University	Press,	Cambridge,	United	Kingdom	and	New	York,	NY,	USA.

18	Brown,	S.,	T.	Pearson,	A.	Dushku,	J.	Kadyzewski,	and	Y.	Qi.	2004.	Baseline	Greenhouse	Gas	Emissions	and	

Removals	for	Forest,	Range,	and	Agricultural	Lands	in	California.	Winrock	International,	for	the	California	

Energy	Commission,	PIER	Energy-Related	Environmental	Research.	500-04-069F.

19 U.S.	EPA,	2009	–	Inventory	of	U.S.	Greenhouse	Gas	Emissions	and	Sinks:	1990	–	2007,	page	8-6.
2012 2.0 GREENHOUSE	GASES	AND	CLIMATE	CHANGE

2.0-26 Second	Recirculated	Draft	EIR	–	SPI	Cogeneration	Power	Project

resources	 that	are	used	as	 fuels.20		This	methodology	–	discussed	in	more	detail	below	–	led	the	

California	 Public	Utilities	 Commission	in	 2007	 to	 find,	in	a	major	 Commission	 decision	 regulating	

greenhouse	gas	emissions:	“electric	generation	using	biomass	 (e.g.,	agricultural	and	wood	waste,	

landfill	gas)	that	would	otherwise	be	disposed	of	under	a	variety	of	conventional	methods	(such	as	

open	burning,	 forest	accumulation,	landfills,	composting)	 results	in	a	substantial	net	 reduction	in	

GHG	emissions.”21

As	 discussed	 above,	 on	 October	 20,	 2011,	 as	 part	 of	 its	 ongoing	 implementation	 of	 AB	 32,	 the	

California	Air	Resources	Board	(CARB)	adopted	regulations	to	implement	a	cap-and-trade	program	

for	 greenhouse	 gas	 emissions.22	 	 In	 section	 95852.2	 of	 the	 regulations,	 CARB	 has	 specifically	

exempted	 from	 any	 compliance	 obligation	 a	 series	 of	 listed	 fuel	 types	 that	 have	 been	

demonstrated	to	be	carbon	neutral,	and	in	many	cases	carbon	negative.23		These	exemptions	cover	

all	of	the	fuel	sources	that	will	be	utilized	at	the	Cogen	Facility.		This	means	that	these	fuels	are	not	

considered	emission	sources	that	need	to	be	capped	or	offset	either	by	the	use	of	allowances,	or	

other	available	offsets	in	the	California	regulatory	program.24		Additionally,	biomass	cogeneration	

facilities	 are	 eligible	 for	 inclusion	 in	 the	 state’s	 Renewable	 Portfolio	 Standard	 (RPS)	 program;	

indeed,	the	Cogen	Facility	has	been	pre-certified	as	a	participating	renewable	energy	facility	by	the	

California	Energy	Commission.

An	article	in	the	October	23,	2009,	issue	of	Science	magazine	challenged	the	notion	that	biomass	

should	be	granted	a	blanket	finding	of	carbon	neutrality,	pointing	out	that	under	some	conditions,	

some	 types	 of	 biomass	 fuels,	 such	as	 fuels	 derived	 from	 forest	 harvesting	 conducted	 specifically	

for	energy	production,	may	not	be	carbon	neutral.25 	However,	the	article	explicitly	acknowledges	

																																																												

20	Morris,	G.,	Biomass	Energy	Production	in	California:	The	Case	for	a	Biomass	Policy	Initiative,	NREL	Report	

No.	NREL/SR-570-28805,	November	2000.

21	California	Public	Utilities	Commission,	Interim	Opinion	on	Phase	1	Issues:	Greenhouse	Gas	Emissions	

Performance	Standard,	D.07-01-039,	pg.	18,	January	25,	2007,	emphasis	in	original.	

22	See	http://www.arb.ca.gov/regact/2010/capandtrade10/capandtrade10.htm	for	more	information	on	

the	rulemaking	process.

23	By	comparison,	the	U.S.	Environmental	Protection	Agency	has	not	yet	determined	whether	or	how	

emissions	from	biomass	generation	must	be	incorporated	into	permits	for	GHG	emissions.		On	January	12,	

2011,	the	EPA	announced	its	intention	to	defer	rulemaking	on	biomass	GHG	permitting	requirements	for	a	

three	year	period	in	order	to	be	able	to	more	fully	study	the	underlying	science.		

24	The	biogenic	emissions	from	biomass	power	generation	will	be	reported	to	the	CARB	under	the	

Mandatory	Reporting	Rule,	but	in	a	separate	category	from	fossil	emissions.		Only	the	fossil	emissions	will	be	

subject	to	the	regulation.

25	Timothy	D.	Searchinger	et	al.,	Fixing	a	Critical	Climate	Accounting	Error,	at	527.
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Second	Recirculated	Draft	EIR	–	SPI	Cogeneration	Power	Project 2.0-27

that	the	use	of	waste	and	residue	 forms	of	biomass	does	not	entail	this	concern,	and	that	waste	

and	residue	forms	of	biomass	should	be	considered	carbon	neutral.		In	fact,	all	of	the	fuels	that	will	

be	used	by	the	proposed	Cogen	Facility	are	waste	and	residue	forms	of	biomass,	and	thus	the	use	

of	these	fuels	should	be	considered	carbon	neutral	or	carbon	negative	fully	within	the	context	of	

the	concerns	expressed	in	the	Science	article.

ANALYSIS	METHODOLOGY

The	proposed	SPI	Anderson	Cogen	Facility	was	analyzed	for	potential	GHG	emissions	from	biogenic	

sources	 (verified	biomass	materials	used	as	 fuel	 for	the	proposed	boiler)	as	well	as	non-biogenic,	

or	 fossil-based	 sources,	 such	 as	 natural	 gas,	 diesel	 fuels,	 etc.	 Table	 2-1	 summarizes	 the	 projectrelated	activities	for	which	the	GHG	emissions	were	estimated,	the	key	input	parameters,	and	the	

source	of	the	emission	factors	to	be	used.		

The	operational	emissions	are	principally	 the	GHG	emissions	 from	 the	combustion	of	biomass	in	

the	facility	(the	stationary	source)	plus	there	are	numerous	support	emissions,	which	are	emissions	

that	directly	support	power	plant	operations	and	would	not	otherwise	occur.	

TABLE	2-1 METHODOLOGIES	USED	TO	ESTIMATE	GHG EMISSIONS	FOR	PROJECT

SOURCE	OF	GHG KEY	INPUT	PARAMETER

GHG EMISSION	FACTORS

MODELS	AND	SOURCES

OPERATIONAL	EMISSIONS

Biomass Combustion at Power 

Plant

Biomass fuel energy content CARB Mandatory Reporting of 

GHG Emissions regulations 

(Title 17 §§95100 to 95133)

Natural Gas Combustion at 

Power Plant

Natural gas energy content CARB Mandatory Reporting of 

GHG Emissions regulations 

(Title 17 §§95100 to 95133)

Fuel Yard Loader Hours of off-road equipment use CARB Offroad2007, CA Climate 

Action Registry General 

Reporting Protocol 2009

Truck Idling at Power Plant Truck idling hours CARB Emfac2007, CA Climate 

Action Registry General 

Reporting Protocol 2009

Employee trips VMT of employee commute trips CARB URBEMIS, CA Climate 

Action Registry General 

Reporting Protocol 2009

Biomass Hauling VMT of haul routes CA Climate Action Registry 

General Reporting Protocol 2009, 

CARB EMFAC2007

Hauling of Ash VMT of haul routes CA Climate Action Registry 

General Reporting Protocol 2009

Biomass Harvesting/Processing On-road vehicle miles traveled 

(VMT) and hours of off-road 

equipment use

CARB Offroad2007, Forest 

Biomass Removal on National 

Forest Lands (Sierra Nevada 

Conservancy, November 2008)
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2.0-28 Second	Recirculated	Draft	EIR	–	SPI	Cogeneration	Power	Project

The	 methodology	 used	 to	 analyze	 the	 project’s	 contribution	 to	 global	 climate	 change	 includes	

the calculation	 of	 GHG	 emissions	 using	 the	 best	 available	 methodologies	 and	 specified	 GHG	

emission	factors	available	from	a	variety	of	models, protocols,	and	regulatory	sources	(as	listed	in	

Table	2-1)	and	the	GHG	Analysis	supporting	Excel	spreadsheets,	which	are	included	as	Appendix	A.

GHG	emission	factors	for	the	calculation	of	total	GHG	emissions	from	the	combustion	of	biomass	

materials	 were	 sourced	 from	 the	 California	 Code	 of	 Regulations,	 and	 the	 equations	 used	 in	 the	

GHG	 analysis	 were	 obtained	 from	 published	 California	 Air	 Resources	 Board	 (CARB)	 guidance	

documents.	 The	results	of	the	quantified	GHG	analysis	are	shown	below	in	Table	2-4.		As	shown	in	

Table	2-4,	emissions	 from	project	operations	are	shown	in	 two	contexts.		The	 first	context	is	 the	

direct	GHG	emissions	 that	would	occur	as	a	 result	of	project	operations,	and	 the	GHG	emissions	

that	 are	 emitted	 directly	 from	 the	 proposed	 cogeneration	 facility	 as	 a	 result	 of	 operation	 are	

shown.		The	second	context	is	 the	net	increase	in	GHG	emissions	 that	would	 result	 from	project	

implementation.	 	 As	 described	 in	 detail	 above,	 the	 combustion	 of	 biomass	 materials	 in	 the	

proposed	cogeneration	plant	would	be	a	carbon	neutral	activity,	since	the	carbon	that	is	released	

from	 the	 combustion	 of	 biomass	materials	is	already	a	 part	 of	 the	earth’s	 carbon	 cycle,	and	the	

combustion	of	this	biomass	material	would	not	result	in	a	net	increase	in	global	carbon	emissions.		

Therefore,	while	the	project	would	result	in	the	direct	emission	of	GHGs	associated	with	biomass	

combustion,	 this	 biomass	 combustion	would	 not	 contribute	 to	a	 net	 increase	 in	GHG	emissions.		

Therefore,	 as	 shown	 in	 Table	 2-4,	 the	 project’s	 GHG	 emissions	 associated	 with	 biomass	

combustion	are	subtracted	from	the	subtotal	of	all	emissions,	as	this	has	been	determined	by	the	

CARB,	the	CEC,	and	the	U.S.	EPA	to	be	a	carbon	neutral	activity,	as	described	throughout	this	EIR	

chapter.		

For	the	processing	of	forest	residues	by	off-road	equipment,	GHG	emission	factors	were	obtained	

via	the	CARB	OFFROAD2007	model.		These	models	and	protocols	represent	established	standards	

used	by	California	regulatory	agencies	and	the	scientific	community.	

GHG	Measurement

Carbon	dioxide	equivalents	(CO2e)	provide	a	universal	standard	of	measurement	against	which	the	

impacts	 of	 releasing,	 or	 avoiding	 the	 release	 of,	 different	 GHGs	 can	 be	 evaluated.	 	 Every	

greenhouse	 gas	 has	 a	 Global	 Warming	 Potential	 (GWP),	 a	 measurement	 of	 the	 impact	 that	

particular	gas	has	on	 radiative	 forcing;	 that	is,	 the	amount	of	heat/energy	 that	is	 retained	in	 the	

Earth's	atmosphere	through	the	addition	of	this	gas	to	the	atmosphere.		The	GWP	of	a	given	gas	

describes	its	effect	on	climate	change	relative	to	a	similar	amount	of	carbon	dioxide	(the	GWP	of	

CO2	is	1.0	by	definition).		

The	GWP	of	a	gas	depends	on	two	factors,	the	ability	of	the	gas	to	absorb	energy,	and	the	lifetime	

of	the	gas	in	the	atmosphere.		GWPs	can	be	expressed	on	an	instantaneous	basis,	which	reflects	

only	 the	 relative	ability	of	 the	gas	 to	absorb	energy,	or	with	an	explicit	 time	 factor	built-in.		The	

residence	 time	 of	 CO2	in	 the	atmosphere	is	generally	 believed	 to	 be	in	excess	 of	 100	years,	and	

some	of	the	other	GHGs	have	even	longer	residence	times.		Thus,	most	analyses	use	a	timeframe	

in	the	range	of	25	–	100	years	in	determining	the	warming	potential	of	GHGs	that	are	emitted	into	

the	atmosphere	today.
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Second	Recirculated	Draft	EIR	–	SPI	Cogeneration	Power	Project 2.0-29

Of	the	five	principal	GHGs,	only	CO2	and	CH4	are	emitted	during	the	combustion	of	fuels,	or	via	the	

degradation	of	biomass.		On	a	per-carbon	basis,	CH4	has	a	GWP	that	is	25	times	greater	than	the	

GWP	 of	 CO2	 on	 an	 instantaneous	 basis.	 	 However,	 the	 average	 residence	 time	 of	 CH4	 in	 the	

atmosphere	is	only	about	one-tenth	as	long	as	the	average	residence	time	of	CO2,	and	its	clearance	

involves	conversion	to	CO2,	so	when	a	time	factor	is	added	the	relative	GWP	of	CH4	goes	down	to	

values	in	the	range	of	7.5–12.5	on	a	per-carbon	basis,	depending	on	the	length	of	the	timeframe	

being	 used	 in	 the	 analysis.	 	 GWPs	 are	 often	 reported	 on	 a	 per-weight	 basis,	 rather	 than	 a	 percarbon	 basis.	 	 The	 instantaneous	GWP	 of	methane	 on	 a	 weight	 basis	 is	 69	 relative	 to	 the	 same	

weight	of	CO2,	and	with	a	time	factor	built-in	it	falls	to	a	range	of	about	20–35.

IMPACTS	AND	MITIGATION	MEASURES

Impact	2.1:		Project	implementation	would	generate	GHG	emissions	that	

may	result	in	a	significant	impact	on	the	environment.		(Less	than	

significant	and	less	than	cumulatively	considerable	impact)

Implementation	of	 the	proposed	project	would	result	in	 the	generation	of	GHG	emissions	during	

the	construction	phase	of	the	project	and	during	operation	of	the	project.		The	construction	phase

of	the	project	is	a	short-term	and	temporary	phase.		The	operational	phase	of	the	project	begins	

once	construction	is	complete,	and	continues	throughout	the	operational	life	of	the	project.		

As	 described	 above,	 the	 proposed	 project	 would	 result	 in	 a	 significant	 and	 cumulatively	

considerable	 impact	 to	 climate	 change	 and	 the	 generation	 of	 GHGs	 if	 project	 operations	 would	

generate	25,000	metric	tons	of	CO2e	per	year,	or	greater.		If	the	project	generates	less	than	25,000	

metric	tons	of	CO2e	per	year,	the	impact	would	be	less	than	significant	and	less	than	cumulatively	

considerable.		

CONSTRUCTION-RELATED	GHG EMISSIONS

Project-related	 construction	 activities	 would	 result	 in	 GHG	 emissions.	 	 Heavy-duty	 off-road	

equipment,	 materials	 transport,	 and	 worker	 commutes	 during	 construction	 of	 the	 proposed	

project	 would	 result	 in	 exhaust	 emissions	 of	 GHGs.	 	 GHG	 emissions	 generated	 by	 construction	

would	be	primarily	in	the	 form	of	CO2.		Although	emissions	of	other	GHGs,	such	as	CH4	and	N2O,	

are	important	with	respect	to	global	climate	change,	the	emission	levels	of	these	other	GHGs	from	

on-	 and	 off-road	 vehicles	 used	 during	 construction	 are	 relatively	 small	 compared	 with	 CO2

emissions,	even	when	factoring	in	the	relatively	larger	global	warming	potential	of	CH4	and	N2O.		

The	estimated	construction	GHG	emissions	are	presented	below	in	Table	2-2.		

TABLE	2-2: CONSTRUCTION	GREENHOUSE	GASES

GREENHOUSE	GAS UNMITIGATED	EMISSIONS	

(TONS/YEAR)

Carbon	dioxide 120.29

SOURCE: DE	NOVO	PLANNING	GROUP, 2010 (URBEMIS 2007	MODELING)
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2.0-30 Second	Recirculated	Draft	EIR	–	SPI	Cogeneration	Power	Project

As	shown	in	Table	2-2,	the	construction	phase	of	the	proposed	project	would	generate	up	to	120	

tons	 per	 year	 of	 CO2.	 	 These	 GHG	 emissions	 would	 occur	 one	 time	 only,	 during	 project	

construction,	and	are	significantly	below	the	established	threshold	of	25,000	metric	tons	of	CO2e	

per	 year.	 	 Therefore,	 construction-related	 GHG	 impacts	 would	 be	 less	 than	 significant,	 and	 no	

mitigation	is	required.		

OPERATIONAL	GHG EMISSIONS

The	 following	 discussion	 describes	 the	 various	 operational	 aspects	 of	 the	 proposed	 project	 that	

would	 generate	 GHG	 emissions	 and	 the	 assumptions	 related	 to	 each	 operational	 aspect	 of	 the	

project	that	were	used	to	quantify	project	GHG	emissions.		

Biomass	Combustion	at	Power	Plant		

The	 proposed	 Cogen	 Facility	 is	 to	 produce	 31	 MW	 (gross)	 of	 electrical	 power	 by	 consuming	

220,000	 bone	 dry	 tons	 (BDT)	 of	 woody	 biomass	 gathered	 from	 a	 variety	 of	 sources.	 	 Based	 on	

information	 supplied	 by	 the	 project	 applicant,	 there	 were	 different	 estimates	 of	 the	 project’s	

biomass	 fuel	blend	by	 fuel	 type.		One	estimate	assumed	 that	 the	entire	project	 (100%)	could	be	

fueled	 by	mill	 residuals	 from	 the	 SPI	 Anderson	 and	 the	 SPI	 Shasta	 Lake	 sawmill	 operations.	It	 is	

reported	 that	 the	 SPI	 Anderson	 Sawmill	 facility	 has	 the	 capability	 to	 provide	 sixty-five	 percent	

(65%)	of	the	fuel	requirements	of	the	proposed	biomass	facility	by	using	100%	of	the	SPI	Anderson	

mill	residuals.	The	remaining	35%	of	the	annual	biomass	needed	can	be	mill	residuals	from	the	SPI	

Shasta	Lake	Sawmill	facility,	located	eighteen	(18)	miles	north	of	the	SPI	Anderson	facility.		

An	alternative	fuel	type	mix	was,	however,	used	for	this	GHG	analysis,	in	order	to	present	a	more	

likely,	average,	fuel	mix	over	the	life	of	the	facility.		It	assumes	that	not	all	the	woody	biomass	for	

fuel	 comes	 from	mill	 residues,	but	also	may	 come	 from	 forest	 harvesting	 operations	 (as	 harvest	

slash),	 forest	thinning	operations	 (to	reduce	wildfire	hazards),	agricultural	woody	waste	 from	the	

Sacramento	Valley	agricultural	areas,	and	some	urban	wood	waste.	

The	 fuel	 mix	 assumptions	 used	 in	 this	 analysis	 are	 considered	 a	 conservative	 “worst-case”	

scenario.		For	example,	by	sourcing	fuel	from	agricultural	woody	waste	sources	in	the	Sacramento	

Valley,	 the	 fuel	 deliveries	 to	 the	 project	 site	 would	 consume	 more	 diesel	 fuel	 (associated	 with	

truck	trips)	than	if	all	of	the	project’s	fuel	were	sourced	from	the	SPI	Anderson	and	SPI	Shasta	Lake	

sawmill	sites.		Additionally,	fuel	supplied	from	in-forest	sources	(slash	and	thinnings)	would	require	

the	 use	 of	 heavy	 machinery	 for	 fuel	 collection	 and	transport.	 	 So	 while	 the	 existing	 sawmills	 at	

Anderson	 and	 Shasta	 Lake	 may	 supply	 100%	 of	 the	 project’s	 fuel	 in	 a	 given	 year,	 the	 project	

applicant	may	 source	up	 to	 35%	of	 the	project’s	 fuel	 from	alternative	 sources	and	locations	in	a	

given	year,	which	may	result	in	increased	emissions	associated	with	fuel	collection	and	transport.		

The	mix	of	biomass	fuel	types	used	in	the	analysis	is	presented	in	Table	2-3	below.
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Second	Recirculated	Draft	EIR	–	SPI	Cogeneration	Power	Project 2.0-31

TABLE	2-3: REPRESENTATIVE	WOODY	BIOMASS	FUEL	MIX	OF	PROJECT

ANNUAL	FUEL	USE MILL

HARVEST	

SLASH

THINNINGS AGRICULTURE

URBAN	

WOOD

TOTAL

BDT	per	year 140,000 20,000 20,000 25,000 15,000 220,000

Percentage	of	BDT 64% 9% 9% 11% 7% 100%

It	 should	 be	 noted	 though,	 that	 in	 the	 calculation	 of	 total	 potential	 GHG	 emissions	 from	 the	

combustion	of	the	woody	biomass,	it	is	the	total	of	220,000	BDT	that	was	used,	as	the	location	of	

where	 it	 came	 from	 for	 this	 calculation	 does	 not	 affect	 the	 total	 GHG	 emissions	 of	 the	 woody	

biomass	combustion.		

Natural	Gas	Combustion	at	the	Power	Plant	

The	proposed	project	will	utilize	natural	gas	during	start	up	and	shut	down	activities,	as	well	as	for	

flame	 stabilization.	 	The	 Cogen	 Facility	 boiler	will	 be	equipped	with	 two	 (2)	 natural	gas	 burners,	

each	 with	 a	 maximum	 rated	 heat	 input	 of	 62.5	 MMBtu/hours.	 	 The	 air	 quality	 permit	 for	 the	

facility	has	not	yet	been	issued,	but	may	have	the	maximum	annual	natural	gas	usage	set	at	10%	of	

the	 burner	 annual	 capacity	 factor.	 	 This	 would	 mean	 that	 that	 the	 natural	 gas	 burners	 could	

operate	 at	 nearly	 3,000	 hours	 per	 year.	 	 However,	 it	 is	 expected	 that	 the	 actual	 usage	 will	 be	

considerably	less	than	this.		Thus,	for	the	purposes	of	GHG	emissions	calculations,	the	natural	gas	

usage	was	set	at	500	hours	of	the	two	burners	operating.		The	assumption	of	500	hours	per	year	of	

burner	 operation	 is	 based	 on	 a	 review	 of	 the	 operational	 characteristics	 of	 similar	 facilities	 in	

Shasta	County,	discussions	with	Shasta	AQMD	staff,	and	professional	knowledge	of	biomass	facility	

operations.	 This	 assumption	 is	 likely	 an	 overestimate	 of	 actual	 burner	 operations	 on	 an	 annual	

basis,	and	is	considered	a	very	conservative	estimate	for	use	in	this	quantification.		

Fuel	Yard	Loader	

The	 GHG	 emissions	 of	 the	 fuel	 yard	 equipment	 are	 included	 in	 the	 operational	 GHG	 emissions	

inventory.		The	equipment	proposed	for	use	in	the	woody	biomass	fuel	yards	is	a	Caterpillar	980B	

Front	End	Bucket	Loader.		Proposed	operational	parameters	are:		Operating	16	hours	per	day,	at	

six	days	a	week	would	equal	112	hour/week,	or	a	total	of	5,284	hours	per	year.		

Truck	Idling		

Woody	 biomass	 from	 the	 forest,	agriculture,	and	 urban	 sources,	as	well	as	a	 portion	 of	 the	mill	

residuals	 coming	 from	 other	 SPI	 facilities	 will	 require	 that	 the	 chip	 van	 trucks	 may	 idle	 at	 the	

facility	while	waiting	to	off	load	woody	biomass	fuel.		The	idling	time	for	each	truck	was	assumed	

to	be	15	minutes.		Ash	hauling	trucks	were	also	included	in	this	GHG	emissions	calculation.

Employee	Trips	

The	SPI	Anderson	Cogen	Facility	project	will	increase	the	number	of	employees	by	six.		Thus,	the	

GHG	emissions	for	six	new	employees	and	their	commute	to	and	from	the	facility	were	calculated.		
2012 2.0 GREENHOUSE	GASES	AND	CLIMATE	CHANGE

2.0-32 Second	Recirculated	Draft	EIR	–	SPI	Cogeneration	Power	Project

Average	trip	length	defaults	were	obtained	from	the	CARB	approved	emissions	models	as	well	as	

average	mix	of	vehicle	types	that	might	be	used	by	the	new,	additional,	employees.

Biomass	Hauling		

Woody	biomass	delivered	 from	the	variety	of	off-site	sources,	including	mill	residuals	 from	other	

SPI	 facilities	 involve	 the	 use	 of	 truck	 and	 chip	 trailers	 combinations.	 	 Based	 upon	 biomass	 fuel	

source	data	supplied	from	SPI,	via	the	County	of	Shasta,	the	average	amount	of	miles	traveled	by	

the	 chip	 trucks	 was	 calculated	 for	 the	 following	 off-site	 biomass	 fuel	 sources.	 	 Included	 is	 the	

calculated	amount	of	fuel	from	these	sources	as	well:

Mill	Residues

• SPI	Shasta	Lake	-	30,135	BDT	@	18	miles

• SPI	Red	Bluff	-	15,043	BDT	@	26	miles

• SPI	Arcata	-	3,724	BDT	@	155	miles

Forest	Thinnings	and	Slash

• Various	locations	-	40,000	BDT	@	68	miles

Agricultural	Woody	Waste

• Sacramento	Valley	various	locations		-	25,000	BDT	@	108	miles

Urban	Wood	Waste

• Sacramento	urban	area	-	15,000	BDT	@	152	miles

The	total	miles	that	the	chip	trucks	would	travel	(round	trips)	was	calculated	and	then	divided	by	

13.5,	this	being	the	average	BDT	of	woody	biomass	per	delivery	truck.		GHG	emissions	factors	for	

heavy-duty	 diesel	 trucks	 were	 then	 applied	 and	 the	 total	 GHG	 emissions	 burden	 for	 diesel	 fuel	

consumed	by	the	trucks	was	calculated.

Hauling	of	Ash	

For	 the	 purposes	 of	 this	 GHG	 emissions	 calculation	 it	 was	 assumed	 that	 all	 the	 ash	 would	 be	

transported	to	the	Anderson	Landfill	for	disposal	(approximately	7.2	miles	away).		An	ash	hauling	

truck	was	assumed	to	hold	18	tons,	and	with	a	projected	annual	generation	of	11,155	tons	of	ash,	

it	 is	 calculated	 that	 there	 will	 be	 1,248	 trips	 to	 the	 landfill	 annually.	 	 Again,	 assuming	 the	truck	

hauling	the	ash	would	be	a	heavy-duty	diesel,	the	GHG	emissions	for	the	diesel	fuel	consumed	was	

calculated.

Biomass	Harvesting	and	Processing	

The	 fuel	 types	 that	 will	 require	 harvesting,	 collection,	 and	 processing	 that	 contribute	 to	 the	

project’s	GHG	emissions	burden	include	the	forest	thinnings	and	slash,	agricultural	woody	waste,	

and	 urban	 wood	 waste.	 	Much	 of	 this	 diesel-fired	 equipment	 (such	 as	 feller	 bunchers,	 grinders,	

etc.)	 is	 off-road	 diesel	 equipment.	 	 There	 are	 some	 on-road	 vehicles	 associated	 with	 the	 forest	

thinnings/slash	and	agricultural	woody	waste	that	were also	used	in	GHG	emissions	calculations.
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Second	Recirculated	Draft	EIR	–	SPI	Cogeneration	Power	Project 2.0-33

Analysis	Results

Table	 2-4	 displays	 the	 results	 of	 the	 GHG	 analysis	 for	 the	 operations	 of	 the	 proposed	 Cogen	

Facility.	 	 Included	 are	 the	 direct	 emissions	 generated	 by	 the	 proposed	 project	 and	 the	 net	

increased	emissions	attributable	to	the	proposed	project.		

Detailed	calculation	worksheets	associated	with	this	table	are	provided	in	Appendix	A.		

TABLE	2-4: DIRECT	AND	NET GHG EMISSIONS	GENERATED	BY	THE	PROJECT

SOURCE

DIRECT EMISSIONS

CO2E	(MT/YEAR)

OPERATIONAL	EMISSIONS

Biomass	Combustion	at	Power	Plant* 317,497

Natural	Gas	Combustion	at	Power	Plant 3,419

Fuel	Yard	Loader 926

Truck	Idling	at	Power	Plant 18

Employee	Trips 39

Biomass	Hauling 1,979

Ash	Hauling 26

Biomass	Harvesting/Processing 5,944

Subtotal	of	emissions	generated 329,848

Exclusion	of	Biomass	Combustion	at	Power	Plant* (317,497)

NET	TOTAL	OPERATIONAL	EMISSIONS 12,351

Notes:

*Biomass	combustion	GHG	emissions	are	shown	to	result	in	zero	net	emissions	since	biomass	combustion	for	the	generation	of	

electricity	is	considered	to	be	carbon	neutral.		The	support	for	the	finding	of	carbon	neutrality	of	biomass	combustion	is	provided	by	the	

following	sources,	and	is	further	described	in	greater	detail	previously	in	this	EIR	chapter.

1. See,	e.g.,	U.S.	Environmental	Protection	Agency,	Inventory	of	U.S.	Greenhouse	Gas	Emissions	and	Sinks,	1990-2008	(April	15,	

2010)	at	3-1	(“It	is	assumed	that	the	carbon	(C)	released	during	the	consumption	of	biomass	is	recycled	as	U.S.	forests	and	

crops	regenerate,	causing	no	net	addition	of	CO2	to	the	atmosphere.”);	U.S.	Department	of	Agriculture,	Forest	Service	Pacific	

Southwest	Research	Station,	Biomass	to	Energy:	Forest	Management	for	Wildfire	Reduction,	Energy	Production,	and	Other	

Benefits,	California	Energy	Commission	report	no.	CEC-500-2009-080	(January	2010);	Intergovernmental	Panel	on	Climate	

Change,	2006	IPCC	Guidelines	for	National	Greenhouse	Gas	Inventories,	Vol.	1,	General	Guidance	and	Reporting	(treating	

biomass	used	for	energy	production	as	having	zero	emissions	in	the	Energy	Sector);	Western	Governors’	Association,	Clean	

and	Diversified	Energy	Initiative,	Biomass	Task	Force	Report	(January	2006).

2. U.S.	EPA,	2009	–	Inventory	of	U.S.	Greenhouse	Gas	Emissions	and	Sinks:	1990	–	2007,	page	8-6.

3. Morris,	G.,	Biomass	Energy	Production	in	California:	The	Case	for	a	Biomass	Policy	Initiative,	NREL	Report	No.	NREL/SR-570-

28805,	November	2000.

4. California	Public	Utilities	Commission,	Interim	Opinion	on	Phase	1	Issues:	Greenhouse	Gas	Emissions	Performance	Standard,	

D.07-01-039,	pg.	18,	January	25,	2007.

5. Mayeur,	Greg.	CARB	Climate	Change	Program	Operations	Sections	Manager.		Personal	communication	(phone)	with	Ben	

Ritchie,	Principal,	De	Novo	Planning	Group.		January	5,	2012.		

SOURCE: TSS CONSULTANTS	AND	DE	NOVO	PLANNING	GROUP	AUGUST	2011	AND	JANUARY	2012.		
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2.0-34 Second	Recirculated	Draft	EIR	–	SPI	Cogeneration	Power	Project

As	 shown	 in	 the	 table	 above,	 operation	 of	 the	 proposed	 Cogen	 Facility	 would	 result	 in	

approximately	 12,351	 metric	 tons	 of	 CO2e	 per	 year.	 This	 level	 of	 GHG	 emissions	 is	 below	 the	

threshold	 of	 25,000	 metric	 tons	 of	 CO2e	 per	 year	 used	 for	 this	 analysis.	 	 Additionally,	 it	 is	

recognized	 that	 this	 analysis	 does	 not	 address	 the	 greenhouse	 gas	 emissions	 that	 would	 be	

generated	by	producing	an	equivalent	amount	of	energy	(31	MW)	from	fossil	fuel	sources	and	that	

would	be	avoided	 through	operation	of	 the	Cogen	Facility,	nor	does	it	account	 for	 the	emissions	

that	 would	 be	 avoided	 by	 using	 the	 fuel	 sources	 for	 the	 Cogen	 Facility	 rather	 than	 alternate	

disposal	 fates	 (such	 as	 open	 burning),	 as	 discussed	 above.	 	 Such	 an	 analysis	 would	 show	 how

greenhouse	gas	emissions	from	the	project	could	fall	even	further	below	the	threshold.		

Therefore,	while	climate	change	represents	a	significant	and	cumulatively	considerable	impact	to	

the	State	of	California,	the	proposed	project	would	result	in	a	less	than	significant	and	less	than	

cumulatively	 considerable	 contribution	 to	 climate	 change	 and	 the	 generation	 of	 GHGs.	 	 No	

mitigation	is	required.		

Impact	2.2:		Project	implementation	may	conflict	with	plans,	policies	and	

programs	adopted	to	reduce	the	generation	of	GHGs (Less	than	significant	

impact)

At	the	time	of	preparation	of	this	EIR,	Shasta	County	has	not	formally	adopted	any	policies,	plans	

or	programs	aimed	at	 reducing	GHG	levels.		The	County	is	in	 the	process	of	preparing	a	Climate	

Action	Plan	 (CAP),	however,	 the	CAP	has	not	yet	been	adopted,	nor	is	it	planned	 for	adoption	in	

the	immediate	future.		It	is	assumed	that	the	CAP	will	contain	goals,	policies	and	implementation	

measures	 intended	 to	 reduce	GHG	 emissions	 throughout	 Shasta	 County.	 	 However,	 it	 is	 not	 yet	

known	if	the	CAP	will	address	emissions	associated	with	biomass	electricity	production.		Given	that	

there	are	no	adopted	plans,	policies	or	programs	in	place	at	 the	local	level	 to	address	GHGs,	 the	

analysis	 of	 this	 impact	 addresses	 the	 proposed	 project’s	 consistency	 with	 State-level	 efforts	 to	

reduce	GHGs.		

On	June	1,	2005,	Governor	Arnold	Schwarzenegger	signed	Executive	Order	S-3-05.		The	goal	of	this	

Executive	Order	is	to	reduce	California’s	GHG	emissions	to:		1)	2000	levels	by	2010,	2)	1990	levels	

by	the	2020	and	3)	80%	below	the	1990	levels	by	the	year	2050.		

In	2006,	this	goal	was	further	reinforced	with	the	passage	of	Assembly	Bill	32	(AB	32),	the	Global	

Warming	Solutions	Act	of	2006.		AB	32	sets	the	same	overall	GHG	emissions	reduction	goals	while	

further	mandating	 that	 CARB	 create	a	 plan,	which	 includes	market	mechanisms,	and	 implement	

rules	 to	 achieve	 “real,	 quantifiable,	 cost-effective	 reductions	 of	 greenhouse	 gases.”	 	 Executive	

Order	 S-20-06	 further	 directs	 state	 agencies	 to	 begin	 implementing	 AB	 32,	 including	 the	

recommendations	made	by	the	state’s	Climate	Action	Team.		

The	AB	32	Scoping	Plan	was	developed	by	CARB	as	the	mechanism,	or	tool,	to	achieve	the	target	

GHG	emissions	reductions	required	by	AB	32.		The	AB	32	Scoping	Plan,	adopted	in	December 2008,

established	 the	 business	as	 usual	 (BAU)	 2020	GHG	emissions	 baseline	at	 596	million	metric	 tons	

(MMT)	 of	 CO2e.	 	 Since	 2008,	 CARB	 has	 updated	 projected	 BAU	 emissions	 based	 on	 current	

economic	 forecasts	 (i.e.,	 as	 influenced	 by	 the	 economic	 downturn)	 and	 reduction	 measures	
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Second	Recirculated	Draft	EIR	–	SPI	Cogeneration	Power	Project 2.0-35

already	in	place.			Two	new	reduction	measures	 [Pavley	I	and	the	Renewables	Portfolio	Standard	

(12%	-	 20%)]	 are	 incorporated	 into	 the	 updated	 baseline	 which	 was	 not	 included	 earlier.	 These	

measures	are	expected	 to	 reduce	 the	 2020	 statewide	emissions	 projection	 to	 507	MMTCO2e	 by	

2020.26	The	updated	forecast	of	507	MMT	CO2e	is	referred	to	as	the	AB	32	2020	baseline.

The	AB	32	Scoping	Plan	has	established	a	2020	GHG	emissions	target	of	427	MMTCO2e,	which	is	80	

MMTCO2e	below	the	projected	2020	GHG	BAU	calculations	of	507	MMTCO2e.		Of	the	80	MMTCO2e	

reduction	 needed	 to	 meet	 the	 2020	 GHG	 emissions	 target,	 21.3	 MMTCO2e	 are	 targeted	 for	

reductions	achieved	through	the	Renewables	Portfolio	Standard.		

Established	 in	 2002	 under	 Senate	 Bill	 1078	 and	 accelerated	 in	 2006	 under	 Senate	 Bill	 107,	

California's	 Renewables	 Portfolio	 Standard	 is	 one	 of	 the	 most	 ambitious	 renewable	 energy	

standards	in	the	country.	The	RPS	program	requires	investor-owned	utilities	(IOUs),	electric	service	

providers,	 and	 community	 choice	 aggregators	to	 increase	 procurement	 from	 eligible	 renewable	

energy	 resources	 by	 at	 least	 1%	 of	 their	 retail	 sales	 annually,	 until	 they	 reach	 20%	 by	 2010.		

Governor	 Arnold	 Schwarzenegger	 signed	 Executive	 Order	 (EO)	 S-21-09	 on	 September	 15,	

2009 directing	 the	CARB	 to	adopt	 regulations	 requiring	 33%	 of	electricity	 sold	in	 the	 state	 come	

from	renewable	energy	by	2020.	Governor	Schwarzenegger	had	previously	established	a	33%	state	

goal	 in	 EO	 S-14-08.	 The	 California	 Public	 Utilities	 Commission	 (CPUC)	 and	 the	 California	 Energy	

Commission	(CEC)	jointly	implement	the	RPS	program.

The	 CEC	 has	 determined	 that	 it	 is	 appropriate	 to	 define	 eligible	 renewable	 energy	 resources	 by	

renewable	 resource	 or	 fuel,	 rather	 than	 by	 the	 specific	 technology	 used.27	 For	 certain	 eligible	

renewable	 energy	 resources,	 however,	 the	 law	 contains	 specific	 requirements,	 and	 the	 Energy	

Commission	 must	 consider	 both	 the	 resource	 or	 fuel	 and	 the	 technology	 to	 determine	 RPS	

eligibility.

To	 qualify	 as	 eligible	 for	 California’s	 RPS,	 a	 generation	 facility	 must	 use	 one	 or	 more	 of	 the	

following	renewable	resources	or	fuels:

•	Biodiesel

•	Biogas	(including	pipeline	biomethane)

•	Biomass

•	Conduit	hydroelectric

•	Digester	gas

•	Fuel	cells	using	renewable	fuels

																																																												

26	California	Air	Resources	Board,	Supplement	to	the	AB	32	Scoping	Plan	Functional	Equivalent	Document.	

June	13,	2011.		Available	at:	http://www.arb.ca.gov/cc/scopingplan/scopingplan.htm

27	California	Energy	Commission,	Commission	Guidebook,	Renewables	Portfolio	Standard	Eligibility	(Fourth	

Edition).	January	2011.		Available	at:	http://www.energy.ca.gov/renewables/documents/index.html#rps
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2.0-36 Second	Recirculated	Draft	EIR	–	SPI	Cogeneration	Power	Project

•	Geothermal

•	Hydroelectric	incremental	generation	from	efficiency	improvements

•	Landfill	gas

•	Municipal	solid	waste

•	Ocean	wave,	ocean	thermal,	and	tidal	current

•	Photovoltaic

•	Small	hydroelectric	(30	megawatts	or	less)

•	Solar	thermal	electric

•	Wind

The	generation	from	a	biomass	facility	is	eligible	for	the	RPS	provided	the	facility	uses	a	“biomass”	

fuel	 as	 defined	 in	 the	 Overall	 Program	 Guidebook.	 	 The	 CEC	 defines	 biomass	 as:	 “any	 organic	

material	not	derived	 from	 fossil	 fuels,	including,	but	not	limited	to,	agricultural	crops,	agricultural	

wastes	 and	 residues,	 waste	 pallets,	 crates,	 dunnage,	 manufacturing,	 construction	 wood	 wastes,	

landscape	and	right-of-way	tree	trimmings,	mill	residues	that	result	from	milling	lumber,	rangeland	

maintenance	 residues,	biosolids,	 sludge	derived	 from	organic	matter,	and	wood	and	wood	waste	

from	timbering	operations.”

28

As	described	above,	the	proposed	project	would	burn	biomass	that	meets	the	CEC’s	definition	of	

eligible	fuels	for	RPS	certification	of	the	facility.		

The	 CEC	maintains	a	 list	 of	 facilities	 currently	 certified	 under	 the	 RPS	 program.	 	 SPI,	 the	 project	

applicant,	has	received	pre-certification	approval	from	the	CEC	to	register	the	proposed	facility	as	

a	renewable	energy	production	facility	under	the	RPS	program.29		The	existing	4MW	cogeneration	

biomass	facility	located	and	operational	at	the	project	site	is	currently	approved	and	certified	as	an	

RPS	 facility.	 	 The	 project	 applicant	 also	 operates	 several	 other	 RPS	 certified	 biomass	 energy	

facilities	throughout	California.		

In	 summary,	 the	 proposed	 project	 has	 received	 pre-certification	 approval	 as	 an	 RPS	 facility.		

Implementation	of	the	proposed	project	will	further	the	goals	established	through	AB	32	and	will	

assist	 with	 implementation	 of	 the	 AB	 32	 Scoping	 Plan	 by	 increasing	 the	 availability	 of	 certified	

renewable	energy	sources	in	California.	CARB	has	determined	that	the	AB	32	Scoping	Plan,	which	

relies	 on	 implementation	 of	 the	 RPS,	 is	 the	 most	 feasible	 and	 aggressive	 program	 available	 to	

reduce	statewide	GHG	emissions.		Energy	produced	from	biomass	is	a	key	component	of	the	RPS,	

and	 the	 proposed	 project	 will	 assist	 in	 implementing	 the	 AB	 32	 Scoping	 Plan	 and	 RPS	 through	

																																																												

28	California	Energy	Commission,	Commission	Guidebook,	Renewable	Energy	Program	Overall	Program	

Guidebook	(Third	Edition).	January	2011.		Available	at:	

http://www.energy.ca.gov/renewables/documents/index.html#rps

29	California	Energy	Commission,	California’s	Renewables	Portfolio	Standard	(RPS)	List	of	Facilities.		August	1,	

2011.		Available	at:	http://www.energy.ca.gov/portfolio/documents/list_RPS_certified.html
2.0 GREENHOUSE	GASES	AND	CLIMATE	CHANGE 2012

Second	Recirculated	Draft	EIR	–	SPI	Cogeneration	Power	Project 2.0-37

contributing	 to	 the	 State’s	 goal	 of	 33%	 of	 California’s	 energy	 needs	 coming	 from	 renewable	

sources.	 	 Therefore,	 the	 proposed	 project	 is	 consistent	 with	 the	 applicable	 regulations	 and	

programs	established	by	the	State	to	reduce	GHG	emissions.		This	is	a	less	than	significant	impact,	

and	no	mitigation	is	required.		

Impact	2.3:		The	effects	of	global	climate	change	could	result	in	adverse	

impacts	on	facility	operations	and	structures.	(Less	than	significant	

impact)30

Recent	increases	in	GHG	concentrations	in	 the	atmosphere	have	lead	 to	increase	average	global	

temperatures	 (global	 warming)	 through	 the	 intensification	 of	 the	 greenhouse	 effect,	 and	

associated	changes	in	local,	regional,	and	global	average	climatic	conditions.

Although	 there	 is	 strong	 scientific	 consensus	 that	 global	 climate	 change	 is	 occurring	 and	 is	

influenced	 by	 human	 activity,	 there	 is	 less	 certainty	 as	 to	 the	 timing,	 severity,	 and	 potential	

consequences	of	the	climate	phenomena.		Scientists	have	identified	several	ways	in	which	global	

climate	change	could	alter	the	physical	environment	in	California.31		These	include:

• increased	average	temperatures;

• modifications	to	the	timing,	amount,	and	form	(rain	vs.	snow)	of	precipitation;

• changes	in	the	timing	and	amount	of	runoff;

• reduced	water	supply;

• deterioration	of	water	quality;	and,

• elevated	sea	levels.

These	changes	may	translate	into	a	variety	of	issues	and	concerns	that	may	affect	the	project	area,	

including,	but	not	limited	to:

																																																												

30This	analysis	is	provided	in	the	interest	of	disclosure,	although	recent	court	decisions	have	held	that	such	

analysis	of	the	effect	of	the	environment	on	a	project	is	not	required	under	CEQA.	See	Ballona	Wetlands	

Land	Trust	v.	City	of	Los	Angeles	(2011)	Case	No.	B231965,__Cal.	App.	4th	__	(2011)	(“[T]he	purpose	of	an	

EIR	is	to	identify	the	significant	effects	of	a	project	on the	environment,	not	the	significant	effects	of	the	

environment	on	the	project.”);	City	of Long	Beach	v.	Los	Angeles	Unified	School	Dist. (2009)	176	Cal.App.4th	

889,	905;	South	Orange	County	Wastewater	Authority	v.	City	of	Dana	Point (2011) 196	Cal.App.4th	1604,	

1614-1618.

31	California	Energy	Commission,	The	Future	is	Now:	An	Update	on	Climate	Change	Science,	Impacts,	and	

Response	Options	for	California.		May	2009.		Available	at:	

http://www.climatechange.ca.gov/publications/biennial_reports/index.html
2012 2.0 GREENHOUSE	GASES	AND	CLIMATE	CHANGE

2.0-38 Second	Recirculated	Draft	EIR	–	SPI	Cogeneration	Power	Project

• decreased	water	supply,	reliability,	and	quality;

• increased	frequency	and	intensity	of	wildfire	as	a	result	of	changing	precipitation	patterns	

and	temperatures;	and,

• increased	risk	of	flooding	and	landslides	associated	with	changes	to	precipitation	patterns.

Although	uncertainty	exists	to	the	precise	levels	of	these	impacts,	there	is	consensus	regarding	the	

range,	frequency,	or	intensity	of	these	impacts	that	can	be	expected.	The	proposed	project	could	

be	 subject	 to	 potential	 hazards	 that	 could	 be	 exacerbated	 by	 climate	 change,	 such	 as	 reduced	

water	 supply,	 increased	 flooding	 that	 might	 prevent	 haul	 trucks	 from	 accessing	 the	 facility,	 and	

increased	grass	or	wildland	fires	from	adjacent	parcels	that	are	primarily	open	space	and/or	used	

for	grazing.	Because	the	project	site	is	located	sufficiently	far	above	sea	level	(more	than	430	feet)	

it	is	not	anticipated	that	the	proposed	project	would	be	affected	by	sea	level	rise.

Although	operation	of	 the	biomass	 facility	may	 result	in	increased	exposure	 to	such	hazards,	 the	

extent	 to	 which	 the	 hazards	 would	 increase	 is	 speculative,	 and	 increases	 in	 hazard	 levels	 would	

occur	over	a	long	time	frame	(e.g.,	100	years	or	more)	compared	to	the	design	life	of	the	project	

(estimated	at	approximately	30	years).	Also,	 the	project	would	include	 features	 that	enable	it	 to	

avoid,	adapt	to,	and	be	resilient	in	the	face	of	climate	change-associated	impacts.	These	features	

include:

• Use	 of	 non-potable	 water	 for	 operation	 of	 the	 steam	 turbine	 and	 direct	 reliance	 on	 a	

source	of	water	that	appears	highly	reliable	given	historical	groundwater	monitoring	of	the	

local	aquifer;

• Use	 of	 water	 conservation	 technologies,	 including	 extensive	 on-site	 recycled	 water	

systems;

• Drainage	features	for	handling	storm	water	runoff	on-site	during	extreme	storm	events;

• Non-vegetated	 setbacks	 between	 the	 biomass	 piles	 stored	 in	 the	 fuel	 yard	and	adjacent	

parcels	that	may	contain	dry	vegetation;	and

• The	existing	 on-site	 fire	 suppression	 system	and	available	water	in	 the	 on-site	 detention	

ponds.

Inclusion	of	these	features	in	the	design	and	operation	of	the	proposed	project	would	reduce	the	

extent	 and	 severity	 of	 climate	 change-related	 impacts	 to	 the	 project	 by	 providing	 methods	 for	

adapting	 to	 these	 changes.	Additionally,	 the	extent	 to	which	 the	 climate	 change-related	 hazards	

would	 increase	 is	 speculative,	 and	 any	 increases	 in	 hazard	 levels	 would	 occur	 over	 a	 long	 time	

frame	compared	to	the	design	life	of	the	project.	For	these	reasons,	this	impact	is	considered	less	

than	significant,	and	no	mitigation	is	required.		
Appendix :   GHG Quantification Worksheets

Completed by:  TSS Consultants, Inc.  
This page left intentionally blank.  
Total	Plant	

Value

Total	Mill	

Residuals Units Source	&	Notes

220,000 140,000 Tons/year Project	descrip7on

High	heat	value 15.38 MMBtu/ton Source	1	-	Appendix	A,	Table	4

Emission	Factors

CO2 93.8 kg/MMBtu Source	1	-	Appendix	A,	Table	4

CH4 30 g/MMBtu Source	1	-	Appendix	A,	Table	6

N2O 4 g/MMBtu Source	1	-	Appendix	A,	Table	6

Annual	Emissions

CO2 317,382 201,970 MT/year Source	2,	Chap.	13,	Equa7on	1

CH4 102 65 MT/year Source	2,	Chap.	13,	Equa7on	1

N2O 14 9 MT/year Source	2,	Chap.	13,	Equa7on	1

CO2e 317,497 202,043 MT/year Global	Warming	Poten7al	calc.

Combus=on	of	Natural	Gas	During	Start	Up	and	Flame	Stabliza=on	

Amount	of	natural	gas	 61.2 MMscf/year

N.G.MMscf/yr	

at	500	hours

N.G.MMscf/yr	

at	2981	hours

Heat	content 1,027 Btu/scf Source	1	-	Appendix	A,	Table	4 61.2 365.36

Amount	of	natural	gas 62,852.4 MMBtu/yr. Calcuated

CO2 0.0544 kg/scf Source	1	-	Appendix	A,	Table	4

CH4 0.9 g/MMBtu Source	1	-	Appendix	A,	Table	6

N2O 0.1 g/MMBtu Source	1	-	Appendix	A,	Table	6

Annual	Emissions

CO2 3,419 MT/year Source	2,	Chap.	13,	Equa7on	1

CH4 0.06 MT/year Source	2,	Chap.	13,	Equa7on	1

N2O 0.01 MT/year Source	2,	Chap.	13,	Equa7on	1

CO2e 3,419 MT/year Global	Warming	Poten7al	calc.

Conversion	Rates

Mass	conversion	rate 1,000 kg/MT www.onlineconversion.com

Mass	conversion	rate 1,000,000 g/MT www.onlineconversion.com

Natural	gas	volume	conversion	rate 1,000,000 scf/MMscf www.onlineconversion.com

Energy	conversion	rate 1,000,000 Btu/MMBtu www.onlineconversion.com

Global	Warming	Poten7al	Compared	to	CO2

CH4 23 unitless IPCC	Assessment	Report	2001

N20 296 unitless IPCC	Assessment	Report	2001

Sources

2	-	CA	Air	Resources	Board,	December	2008.		Instruc7onal	Guidance	for	Mandatory	GHG	Emission	Repor7ng.		At:	

www.arb.ca.gov/cc/repor7ng/ghg-rep/ghg-reg-guid/ghg-rep-guid.htm

Annual	GHG	Emissions	from	On-Site	Woody	Biomass	Combus=on	(Including	Natural	Gas	Start-up	and	Flame	Stabiliza=on)

Annual	heat	input	from	firing	natural	

gas	based	on	500	hours

Combus=on	of	Biomass	During	Normal	Opera=ons

Facility	Specifica=ons

Amount	of	biomass	combusted

Emission	Factors

1	-	CA	Regula7ons	for	the	Mandatory	Repor7ng	of	GHG	Emissions	(§§95100	to	95133	Title	17	CA	Code	of	Regula7ons).		

At:	www.arb.ca.gov/regact/2007/ghg2007/frofinoal.pdf
Emissions	from	Biomass	Hauling	to	Power	Plant

Mill	Residues

Forest	Slash	and	

Thinnings

Agricultural	

Wood	Waste

Urban	

Wood	

Waste

64% 18% 11% 7%

140,000 40,000 25,000 15,000

Amount	in	BDT

Percentage	of	

Mill	Residue	

Fuel	Type

Percentage	of	

Total	Fuel	

Types

Average	

BDT	per	

Truck

Calculated	

number	of	

Trucks

Average	

VMT*	

VMT	per	

Round	Trip

Total	

Number	of	

Miles

91,000 65% 13.5 6,741 0 0 0

30,135 22% 13.5 2,232 18 36 80,360

Mill	Residues	from	SPI	Red	Bluff 15,043 11% 13.5 1,114 26 52 57,943

3,724 3% 13.5 276 155 310 85,514

40,000 18% 13.5 2,963 68 136 402,963

25,000 11% 13.5 1,852 108 216 400,000

15,000 7% 13.5 1,111 152 304 337,778

TOTAL 1,364,558

Value Units Source

1,364,558 Miles Calculated

Heavy	Duty	Diesel	Vehicle	Emission	Factor 1,450 g/mile Source	1

Total	Annual	Hauling	Emissions 1,979 MT/year

*VMT	-	vehicle	mile	traveled

Sources

64%

1	-	California	Climate	AcUon	Registry	General	ReporUng	Protocol,	Version	3.1,	Table	C.3,	January	2009.	

Biomass	Hauling	Emissions

Biomass	Haul	Miles

Percentage	Breakdown	by	Fuel	Type,	Origin,	and	Average	VMT

Mill	Residues	from	SPI	Anderson	Plant

Mill	Residues	from	SPI	Shasta	Lake	

Forest	Slash	and	Thinning

Agricultural	Wood	Waste

Urban	Wood	Waste

Mill	Residues	from	SPI	Arcata

Percentage	breakdown	as	BDT

BDT
Summary	of	CO2	Emission	Rate	Associated	with	Harves;ng	and	Processing	of	Biomass	Per	Bone	Dry	Ton

Value Units

25.54 lbCO2/BDT

2.92 lbCO2/BDT

6.3 lbCO2/BDT

24.96 lbCO2/BDT

9.04 lbCO2/BDT

8.48 lbCO2/BDT

9.95 lbCO2/BDT

45.78 lbCO2/BDT

45.78 lbCO2/BDT

84.78 lbCO2/BDT

263.53 lbCO2/BDT

4,775 MT/year

25.54 lbCO2/BDT

6.3 lbCO2/BDT

8.48 lbCO2/BDT

45.78 lbCO2/BDT

86.1 975

975 MT/year

25.54 lbCO2/BDT

2.92 lbCO2/BDT

None

28.46

193 MT/year**

5,944 MT/year

**Due	to	the	compara.vely	very	small	level	of	emissions	from	N2O	and	CH4,	even	when	factoring	in	their	global	warming	poten.al,	these	

emissions	would	not	significantly	change	the	CO2	emission	levels

(does	not	include	biomass	haul	to	power	plant)

Forest	Thinning,	Harvested/Processed	Biomass

Off-Road	Equipment

Horizontal	grinder

Small	excavator	loader

Feller	bundher

Grapple	skidder

TOTAL

Large	excavator	loader

Crew	truck

On-Road	Vehicles

Truck/chip	van

Water	truck

Service	truck

Crew	truck

Low	bed	truck

Agricultural	Waste,	Harvested/Processed	Biomass

Off-Road	Equipment

Horizontal	grinder

Large	excavator	loader

On-Road	Vehicles

Truck/chip	van

TOTAL

Methodology:		Off-road	CO2	emissions	derived	from	the	CARB	OFFROAD	2007	model.		On-road	CO2	emissions	derived	from	the	

EMFAC2007	model.			The	above	equipment	list	is	based	upon	a	demonstra.on	project	conducted	for	the	Sierra	Nevada	

Conservancy	in	2008	in	the	Tahoe	Na.onal	Forest.

*	A	conserva.ve	assump.on	is	made	here	that	urban	wood	waste	consumed	at	the	biomass	power	plant	would	need	to	be	

chipped	even	though	all	urban	wood	waste	is	nonetheless	chipped	prior	to	diversion	to	other	uses	(i.e.,	mulch,	soil	amendment,	

daily	cover,	fuel	to	biomass	plants,	etc.)

TOTAL

Urban	Wood	Waste,	Harvested/Processed	Biomass*

Off-Road	Equipment

Horizontal	grinder

Small	excavator	loader

On-Road	Vehicles

Biomass	Harvested/Processed	Total	Emissions
Fuel	Yard	Equipment	CO2	Emissions

Equipment	Specifica9ons

Value Units Descrip/on Source/notes

Front	end	bucket	loader 1 Unit CAT	980	B LeAer	dated	7/13/11	from	Sierra	Pacific	to	Shasta	County

Daily	hours 16 hr/day LeAer	dated	7/13/11	from	Sierra	Pacific	to	Shasta	County

Days	per	week	 7 days/week LeAer	dated	7/13/11	from	Sierra	Pacific	to	Shasta	County

Weeks	per	year 52 weeks/yr Calculated

Hours	per	year 5824 hours/yr LeAer	dated	7/13/11	from	Sierra	Pacific	to	Shasta	County

Year	of	fleet 2011

Mass	conversion 2,000 lb/ton onlineconversion.com

Mass	conversion 2,205 lb/MT onlineconversion.com

Units Source

Emission	Factor	for	Loader 159 kg/hour Source	1

Annual	Emissions 926 MT/year

Sources

1	-	California	Climate	Ac/on	Registry	General	Repor/ng	Protocol,	Version	3.1,	Table	C.3,	January	2009.	

*Due	to	the	compara0vely	very	small	level	of	emissions	from	N2O	and	CH4,	even	when	factoring	in	their	global	warming	poten0al,	these	emissions	

would	not	significantly	change	the	CO2	emission	levels
Value Units Source

10,370 trucks/year Calculated

Trucks	hauling	ash

(11,155	tons	@	18	tons	per	truck) 620 trucks/year Calculated

10,990 trucks/year Calculated

Average	length	of	truck	visit	w/idle 0.25 hours/visit AssumpLon

2748 hours/year Calculated

6,542 g/idle	hour EMFAC	2007

19.8 ton/year Calculated

Annual	(MT/year) 18.0 MT/year Calculated

*Due	to	the	compara.vely	very	small	level	of	emissions	from	N2O	and	CH4,	even	when	factoring	in	their	global	warming	poten.al,	these	emissions	

would	not	significantly	change	the	CO2	emission	levels

Truck	Idling	Emissions	

Truck	Idling	Hours	On-Site

(140,000	BDT	@	13.5	BDT	per	truck)

Trucks	hauling	biomass	to	site	

Combined	truck	visits

Truck	idle	hours

Emission	factor	truck	idle	

HHD-DSL	(Heavy	duty	diesel	truck)

Truck	idling	emissions

Annual	(tons/year)
Ash	Hauling	Trip	Characteris3cs

Truck	loads	associated	with	hauling	away	of	ash	to	landfill

Units Value Source/notes

tons 									11,155

tons 18

trucks 2.0

trucks 2.0

trips/load 4.0

trips 1248 calculated

miles 14.6

miles 									18,221 caluclated

CO2 Source

1,450 Source	1

Value Units Source

454 g/lb onlineconversion.com

Mass	conversion	rate 2,000 lb/ton onlineconversion.com

Mass	conversion	rate 1,000,000 g/MT onlineconversion.com

Time	conversion 312 days assume	ash	hauling	6	days	a	week

Annual	Emissions	for	Ash	Hauling	Trucks 26.4 MT/year Calculated

Sources

*Due	to	the	compara0vely	very	small	level	of	emissions	from	N2O	and	CH4,	even	when	factoring	in	their	global	warming	poten0al,	these	emissions	would	not	

significantly	change	the	CO2	emission	levels

Total	Truck	VMT	

Google	maps

Number	of	trips	per	year

Trip	length	(SPI	facility	to	landfill	and	return)

1	-	California	Climate	AcSon	Registry	General	ReporSng	Protocol,	Version	3.1,	Table	C.3,	January	2009.	

CO2	Emission	Factor	for	Ash	Haul	Truck

Emission	rate	@45	miles	per	hour	with	HHD-DSL	truck	(g/mile)

Conversion	rates	used

Mass	conversion	rate

Yearly	producSon	of	ash

Amount	per	truck	load

Maximum	daily	truck	loads	(assume	6	days/wk,	312	days/year)

Average	annual	daily	truck	loads

Associatd	trips	per	day	per	truck

project	descripSon

assumpSon

calculated

calculated
Units Value

employees 6

trip/day 12

miles/trip 14.7

Total	miles/day miles 176.4 Calculated

Total	miles/year miles 64,386 Calculated	using	365	days

No.	of	vehicle	type	miles Average	MPG Gallons Fuel	Type

38% 24,338 22 1,106 gasoline

29% 18,350 18 1,019 gasoline

23% 14,744 10 1,474 gasoline

11% 6,889 7 984 diesel

100%

CO2*

Maximum	daily	(lb/year) 86,325

Annual	(ton/year) 43

Value Units Source

Mass	conversion	rate 0.907 MT/ton onlineconversion.com

CO2	Emissions	per	year 39 MT/year Calculated

Employee	Trip	Emissions

Employee	Trip	Genera7on	Rate

Daily	employees

Employee	trips	per	day

Trip	length

Source/notes

Project	descripWon

To/from	site

URBEMIS	default	trip	length

Calculated

*Due	to	the	compara.vely	very	small	level	of	emissions	from	N2O	and	CH4,	even	when	factoring	in	their	global	warming	poten.al,	these	emissions	would	not	

significantly	change	the	CO2	emission	levels

Calculated

Source

Fleet	Mix	for	Employee	Trips

Vehicle	type

Light	auto

Light	truck	<3,750	lb

Light	truck	3,751	to	5,750	lb

Medium	truck	5,751	to	8,500	lb

TOTAL

Maximum	Daily	Emissions	from	Employee	Trips

ProporWon	used	in	Model	run	%
Emission	

Factor

Emission	Factor	

Units

Emission	

Factor	

Source

Mobile	Combus7on

Gasoline 8.81 kg	CO2/gallon 17.86 lbs/CO2	gal California	Climate	AcWon	Registry	General	ReporWng	Protocol,	Version	3.1,	Table	C.3,	January	2009.	

Diesel 10.15 kg	CO2/gallon 22.38 lbs/CO2gal California	Climate	AcWon	Registry	General	ReporWng	Protocol,	Version	3.1,	Table	C.3,	January	2009.