Denver / North Front Range Fuel Supply Costs and Impacts

E A I I n c | E n e r g y A n a l y s t s I n t e r n a t i o n a l
Denver / North Front Range
Fuel Supply Costs
and Impacts
2011
MESA
MONTROSE
DOLORES
MOFFAT
SAN MIGUEL
MONTEZUMA
RIO BLANCO
DELTA
OURAY
LA PLATA
GARFIELD
HINSDALE
ROUTT
PITKIN
GUNNISON
ARCHULETA
EAGLE
JACKSON
LAKE
GRAND
CHAFFEE
SAGUACHE
MINERAL
RIO GRANDE
CONEJOS
Report for
Regional Air Quality Council
March 4, 2011
CLEAR
CREEK
PARK
LARIMER
GILPIN
ALAMOSA
BOULDER
JEFFERSON
FREMONT
CUSTER
COSTILLA
DENVER
DOUGLAS
TELLER
HUERFANO
WELD
ADAMS
ARAPAHOE
EL PASO
PUEBLO
ELBERT
LAS ANIMAS
MORGAN
LINCOLN
CROWLEY
OTERO
LOGAN
WASHINGTON
BENT
KIT CARSON
CHEYENNE
KIOWA
SEDGWICK
BACA
PHILLIPS
DENVER
FRONT RANGE
MARKET
YUMA
PROWERS
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TABLE OF CONTENTS
SECTION DESCRIPTION PAGE#
A ES EXECUTIVE SUMMARY
Introduction ES‐ 1
RAQC Mission ES‐ 2
Purpose of Study and Task Overview ES‐ 2
Colorado Gasoline Market & RAQC Program Area ES‐ 3
Status & Operation of the Colorado Product Supply Network ES‐ 4
Impact of Gasoline Specification Changes ES‐ 7
B OV OVERVIEW OF THE CO & FRONT RANGE FUELS MARKET
Introduction OV‐ 1
Gasoline Demand in Colorado OV‐ 2
Colorado Front Range Gasoline Supply Sturcture OV‐ 6
Summary of Colorado Market Supply & Demand OV‐ 11
C REF REFINING AND GASOLINE SUPPLY
Introduction REF‐ 1
Refinery Process Unit & Operation Review REF‐ 1
Major Refineries Supplying The Colorado/Front Range Markets REF‐ 4
Overview of the Colorado Front Range Refinery Supply Network REF‐ 4
Suncor Commerce City Refinery REF‐ 5
Frontier Cheyenne Refinery REF‐ 6
Sinclair Rawlines Refinery REF‐ 6
Frontier El Dorado Refinery REF‐ 7
WRB ‐ ConocoPhillips Borger Refinery REF‐ 8
Valero McKee Refinery REF‐ 8
Operations Summary REF‐ 9
Refinery Supply Costs Impact REF‐ 10
Higher RVP Options: 7 PSI CBOB With Waiver & 7.8 PSI CBOB No Waiver REF‐ 11
Low RVP Options: 7 PSI CBOB No Waiver & Reformulated Gasoline REF‐ 12
Impact Summary REF‐ 13
D DST DISTRIBUTION & NETWORK BALANCE FORECASTS
Introduction DST‐ 1
Market Price Impacts ‐ Low RVP & RFG Options DST‐ 2
Distribution System Impacts DST‐ 3
E BIO BIOFUEL SUPPLY DEMAND OUTLOOK ETHANOL & BIODIESEL
Introduction BIO‐ 1
Ethanol Overview BIO‐ 1
Ethanol Blended Gasoline BIO‐ 2
Corn Ethanol Economics BIO‐ 3
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TABLE OF CONTENTS
SECTION DESCRIPTION PAGE#
Ethanol Based Engines BIO‐ 4
BioFuel Mandates BIO‐ 4
Current Ethanol Usage BIO‐ 8
Tax Incentive for Ethanol BIO‐ 9
Cellulosic Ethanol BIO‐ 9
Ethanol Demand Outlook BIO‐ 10
National BIO‐ 10
Ethanol Supply Outlook BIO‐ 12
Ethanol Logistics & Pricing BIO‐ 16
Ethanol Logistics BIO‐ 16
Ethanol Pricing BIO‐ 19
Renewable Fuels Standard Overview BIO‐ 23
New RFS Regulations BIO‐ 23
Introduction BIO‐ 23
Greenhouse Gas Reduction Thresholds BIO‐ 23
Treatment of Required Volumes in 2009 BIO‐ 24
Final Standards for 2010 BIO‐ 25
Program Design & Proposed Implementation Approach BIO‐ 25
Overview of Impact of the Rule BIO‐ 26
Greenhouse Gas Emissions BIO‐ 26
Emissions & Air Quality BIO‐ 27
Renewable identification Number (RIN) BIO‐ 27
Colorado Ethanol BioDiesel Outlook BIO‐ 31
F REG PRODUCT REGULATIONS
Introduction REG‐ 1
Ozone Pollution REG‐ 1
Gasoline Regulations REG‐ 4
Overview of Federal Regulations REG‐ 4
Mobile Sources Air Toxics (MSAT) REG‐ 7
Introduction REG‐ 7
Gasoline Benzene Regulations REG‐ 8
Small Refiner Flexibilities REG‐ 8
Benezene Pre‐Compliance Reporting Requirements REG‐ 9
Benezene Pre‐Compliance Reports REG‐ 10
American Recovery & Reinvestment Act of 2009 REG‐ 11
Economic Stimulus Plan REG‐ 11
Greenhouse Gas (GHG) Emissions REG‐ 11
American Clean Energy & Security Act of 2009 REG‐ 12
Introduction REG‐ 12
Cap & Trade Program REG‐ 12
Summary REG‐ 13
APX APPENDIX
Glossary of Terms APX‐ 1
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LIST OF FIGURES
FIGURE# DESCRIPTION PAGE#
A ES EXECUTIVE SUMMARY
ES‐ 1 Denver‐Boulder‐Greeley‐Fort Collins / Eight Hour Ozone Control Area ES‐ 1
ES‐ 2 Gasoline Demand Distribution / CO by Geography & Ozone Attainment ES‐ 3
ES‐ 3 Refined Product Network Status / Rocky Mountain Region ES‐ 4
ES‐ 4 Colorado Light Product Supply Chain & Capabilities, 2009 MBPD ES‐ 6
ES‐ 5 Gasoline Supply Share by Refiner: Colorado Front Range ES‐ 6
ES‐ 6 Manufacturing Cost Increases Due To Fuels Specification Changes ES‐ 8
ES‐ 7 Front Range Light End Rejection to Meet RVP & 1 lb Waiver Options ES‐ 9
ES‐ 8 Movement of Gasoline Into Attainment Areas ES‐ 11
B OV OVERVIEW OF THE CO & FRONT RANGE FUELS MARKET
OV‐ 1 Denver‐Boulder‐Greeley‐Fort Collins / Eight Hour Ozone Control Area OV‐ 2
OV‐ 2 Gasoline Demand Distribution/CO by Geography & Ozone Attainment OV‐ 3
OV‐ 3 Seasonality of Colorado Gasoline Demand OV‐ 5
OV‐ 4 Annual Colorado Gasoline Demand OV‐ 6
OV‐ 5 U.S. Refined Product Supply‐Demand Network OV‐ 7
OV‐ 6 Refined Product Supply ‐ Pipelines & Refineries OV‐ 8
OV‐ 7 Current Colorado Front Range Gasoline Supply Envelope OV‐ 9
OV‐ 8 Refined Product Network Status / Rocky Mountain Region OV‐ 10
OV‐ 9 Western Region Refined Product Network/Project Updates & Key Bus. Drivers OV‐ 11
OV‐ 10 Colorado Light Product Supply Chain & Capacities, 2009 MBPD OV‐ 12
C REF REFINING AND GASOLINE SUPPLY
REF‐ 1 Generalized Refinery Process Schematic REF‐ 1
REF‐ 2 Aggregate Refinery Representing Primary Plants Supplying Colorado REF‐ 11
REF‐ 3 Front Range Light End Rejection to Meet RVP & 1LB Waiver Options REF‐ 15
REF‐ 4 Front Range Gasoline Pool Blending to Meet RVP & 1LB Waiver Options REF‐ 16
REF‐ 5 Potential Gasoline volume Loss & Shift / Denver Front Range Market REF‐ 17
REF‐ 6 Loss of Value Selling Denver Gasoline at Conway Natural Gasoline Price REF‐ 18
REF‐ 7 Manufacturing Cost Increases Due to Fuels Specification Changes REF‐ 19
D DST DISTRIBUTION & NETWORK BALANCE FORECASTS
DST‐ 1 Refined Product Supply ‐ Pipelines & Refineries DST‐ 1
DST‐ 2 Reformulated Gasoline Market vs Conventional DST‐ 3
DST‐ 3 Colorado Front Range Gasoline Supply Envelope DST‐ 4
DST‐ 4 Movement of Gasoline Into Attainment Areas DST‐ 5
DST‐ 5 Colorado Gasoline Distribution by Ozone Attainment Status & Source DST‐ 6
DST‐ 6 Refined Product Supply Network / Denver ‐ Colorado Front Range DST‐ 7
E BIO BIOFUEL SUPPLY DEMAND OUTLOOK ETHANOL & BIODIESEL
BIO‐ 1 Federal Mandate for Total Ethanol Use Under EISA 2007 BIO‐ 5
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LIST OF FIGURES
FIGURE# DESCRIPTION PAGE#
BIO‐ 2 Federal Mandate for Corn Ethanol Use ‐ EISA 2007 ‐ Actual for 2008 BIO‐ 6
BIO‐ 3 Federal Mandate for Cellulose Ethanol Use EISA ‐ 2007 BIO‐ 6
BIO‐ 4 U.S. Gasoline Consumption Forecast / Reformulated & Oxygenated Fuels BIO‐ 11
BIO‐ 5 U.S. Gasoline Consumption Forecast / Based on Federal Ethanol Mandate BIO‐ 11
BIO‐ 6 New Capacity for Corn & Advanced Biofuels BIO‐ 13
BIO‐ 7 U.S. Ethanol Production Outlook / Plant Construction Activity BIO‐ 14
BIO‐ 8 U.S. Fuel Ethanol Existing & Under Const./Est. Capacity vs Prj. Demand BIO‐ 15
BIO‐ 9 EAI, Inc. U.S. Ethanol Balances / Jan‐Oct 2009, MBPD BIO‐ 17
BIO‐ 10 Relative Market Terminal Ethanol Saturation BIO‐ 17
BIO‐ 11 Spot Product Price Spreads to Crude/Chicago Spot Gasoline & Diesel to WTI BIO‐ 19
BIO‐ 12 Ethanol Blending Incentive BIO‐ 20
BIO‐ 13 Ethanol Transportation Rates To Major Markets BIO‐ 21
BIO‐ 14 Ethanol Market Margins ‐ Chicago Origin BIO‐ 21
BIO‐ 15 Brazil Ethanol Imports ‐ Northeast Ports BIO‐ 22
BIO‐ 16 Estimated Federal Mandate Percent of Total Gasoline for CO Ethanol Use BIO‐ 32
BIO‐ 17 Estimated Federal Mandate for Colorado Ethanol Use (EISA 2007) BIO‐ 32
BIO‐ 18 Denver Front Range Ethanol Supply Availability by Distance (Miles) BIO‐ 33
BIO‐ 19 Ttl Corn Ethanol Demand for Tri‐State Area vs Current Production Capacity BIO‐ 33
BIO‐ 20 Estimated Federal Mandate for CO Biomass Diesel Use Under EISA 2007 BIO‐ 34
BIO‐ 21 Denver Front Range Biodiesel Supply Availability by Distance (Miles) BIO‐ 34
F REG PRODUCT REGULATIONS
REG‐ 1 EPA Ozone Non‐Attainment Areas REG‐ 3
REG‐ 2 Mandated Reformulated Gasoline Market Areas REG‐ 5
REG‐ 3 Gasoline Environmental Grades By Market Area REG‐ 6
APX APPENDIX
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DENVER NFR FUEL SUPPLY COSTS AND IMPACTS 2010
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LIST OF TABLES
TABLE# DESCRIPTION PAGE#
A ES EXECUTIVE SUMMARY
B OV OVERVIEW OF THE CO & FRONT RANGE FUELS MARKET
OV‐ 1 Colorado State Level Refined Product Balance ‐ 2009 OV‐ 13
C REF REFINING AND GASOLINE SUPPLY
REF‐ 1 Refinery Configuration Matrix/CO Front Range Supply Refineries REF‐ 20
REF‐ 2 Refining Company Operations Summary 2009 REF‐ 21
REF‐ 3 Ozone Fuel Scenario Impact Matrix REF‐ 22
D DST DISTRIBUTION & NETWORK BALANCE FORECASTS
E BIO BIOFUEL SUPPLY DEMAND OUTLOOK ETHANOL & BIODIESEL
BIO‐ 1 U.S. Fuel Ethanol Production Capacity (Existing & Under Construction) BIO‐ 35
BIO‐ 2 U.S. Cellulosic Ethanol Projects Under Development & Construction BIO‐ 38
BIO‐ 3 Colorado FR Local Ethanol Supply/Major Ethanol Plants in 400 Miles BIO‐ 39
BIO‐ 4 Colorado FR Local Biodiesel Supply/Major Biodiesel Plants in 400 Miles BIO‐ 40
F REG PRODUCT REGULATIONS
APX APPENDIX
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DENVER NFR FUEL SUPPLY COSTS AND IMPACTS 2010
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ES
EXECUTIVE SUMMARY
EAI, INC. (ENERGY ANALYSTS INTERNATIONAL) EAI, INC.
DENVER NFR FUEL SUPPLY COSTS AND IMPACTS 2011

INTRODUCTION
EXECUTIVE SUMMARY
This report, Denver/North Front Range Fuel Supply Costs and Impacts, was prepared for the
Denver Regional Air Quality Council (RAQC) by EAI, Inc. (Energy Analysts International). RAQC has
responsibility for implementing strategies for the air quality attainment in the Denver Metropolitan
Area – North Front Range area. This area is shown in Figure ES‐1.
Figure ES‐1
Denver-Boulder-Greeley-Fort Collins
Eight Hour Ozone Control Area
Copyright ©: EAI, Inc., 2011
The defined area includes the highly populated areas extending from Castle Rock in the south,
through Denver – Boulder and up to Fort Collins. This area is supplied with gasoline from a select
number of refineries located both within the area and external to the area with major supply
volumes being transported to the area by product pipelines. A significant amount of gasoline
supply is trucked from product terminals located within the non‐attainment area to peripheral
markets located in the ozone attainment area since there are limited alternative sources of product
to economically supply these areas.
The purpose of conducting this study is to evaluate the impacts of choosing a more stringent
formulation of summertime gasoline for the Denver/North Front Range market. These impacts can
EAI, INC. (ENERGY ANALYSTS INTERNATIONAL) EAI, INC.
DENVER NFR FUELS SUPPLY COSTS AND IMPACTS 2011
ES‐1

EXECUTIVE SUMMARY
take a number of forms including additional gasoline supply costs due to increased manufacturing
costs and changes in in the sourcing of gasoline supply due to decisions by refiners to not invest in
the equipment needed to produce the more stringent gasoline specifications. Both of these
situations can potentially add significant costs to the consumer price of gasoline.
RAQC MISSION
RAQC is in the process of developing a set of recommended actions to reduce ozone precursor
emissions from mobile sources via changes in motor gasoline specifications. The gasoline
specification options to be considered include the following:
1. Retain the current 7.8 RVP summertime standard, but eliminate the one psi ethanol waiver
2. Adopt a 7.0 RVP summertime standard and retain the one psi ethanol waiver
3. Adopt a 7.0 RVP summertime standard and eliminate the one psi ethanol waiver
4. Opt‐into the federal Reformulated Gasoline Program (RFG).
The ozone non‐attainment area that these gasoline specification changes are proposed for is the
Denver Metropolitan Area – North Front Range Area. An option of applying for a waiver on ethanol
blending was considered but was decided to not be a viable option. Similarly impacts of the
approval of E15 gasoline were not evaluated.
PURPOSE OF STUDY AND TASK OVERVIEW
As noted above, the purpose of this study is to provide an assessment of various fuel strategies for
the Denver/North Front Range relative to feasibility, cost impacts and likely supply scenarios. This
assessment was achieved through a combination of survey work, analysis and modeling by EAI, Inc.
Task 1: Summarize the Colorado and Front Range Fuels Market
Task 2: Describe the capabilities of the refineries
Task 3: Quantify cost impacts
Task 4: Quantify distribution impacts
Task 5: Quantify ethanol and biofuel impacts
Task 6: Describe impacts of current and proposed Federal rules
The overall goal is to assess the market impacts of the various proposed fuel strategies, the costs
incurred to make the designated fuel (capital and operating) and how a particular fuel specification
may impact the sourcing and availability of summer gasoline for the Colorado‐Front Range market.
EAI, INC. (ENERGY ANALYSTS INTERNATIONAL) EAI, INC.
DENVER NFR FUELS SUPPLY COSTS AND IMPACTS 2011
ES‐2

COLORADO GASOLINE MARKET AND RAQC PROGRAM AREA
EXECUTIVE SUMMARY
An overview of the state of Colorado and the Denver North Front Range program area are shown in
Figure ES‐2 with estimates of gasoline consumed in the various sub‐regions.
Figure ES‐2
Gasoline Demand Distribution
Colorado by Geography and Ozone Attainment Status, 2009
Total Gasoline Demand at 136.8 MBPD
Western CO
Demand = 16
MBPD
MESA
DELTA
GRAND JUNCTION
MONTROSE
DOLORES
MONTEZUMA
MOFFAT
RIO BLANCO
GARFIELD
MARKET
WESTERN SLOPE
OURAY
SAN MIGUEL
LA PLATA
HINSDALE
ROUTT
PITKIN
GUNNISON
MINERAL
RIO GRANDE
ALAMOSA
ARCHULETA
EAGLE
JACKSON
LAKE
GRAND
CHAFFEE
SAGUACHE
CONEJOS
LARIMER
GILPIN
BOULDER
CLEAR CREEK
PARK
JEFFERSON
FREMONT
CUSTER
COSTILLA
Copyright ©: EAI, Inc., 2011
EAI, INC. (ENERGY ANALYSTS INTERNATIONAL) EAI, INC.
DENVER NFR FUELS SUPPLY COSTS AND IMPACTS 2011
ES‐3
DENVER
ADAMS
DOUGLAS
TELLER
HUERFANO
WELD
ARAPAHOE
EL PASO
PUEBLO
COLO SPR – PBLO
MARKET
ELBERT
LAS ANIMAS
MORGAN
LINCOLN
CROWLEY
OTERO
LOGAN
DENVER
FRONT RANGE
MARKET
WASHINGTON
BENT
KIT CARSON
CHEYENNE
KIOWA
SEDGWICK
BACA
PHILLIPS
YUMA
Denver-Front Range
Demand
Ozone NA = 78 MBPD
Ozone ATN = 18 MBPD
Southeast CO
Demand = 24
PROWERS
MBPD
Total Colorado gasoline demand was 136.8 MBPD (1000 BPD) in 2009. EAI, Inc.’s forecast for
gasoline consumption in Colorado is for gasoline demand to recover in 2010, remain basically flat
until 2013 and then undergo a long period of slow decline with forecasted demand levels of 135
MBPD in 2020 and 123 MBPD in 2030.
Based on EAI, Inc.’s latest Micro‐Market Demand analysis, the total gasoline demand in the Front
Range non‐attainment area is 78.1 MBPD. The total Colorado demand for gasoline outside the
non‐attainment area is 61.4 MBPD. The overall Eastern Central and Northeast Colorado area
demand from Douglas country north to the state border and East to the KS border is 96.0 MBPD
consisting of 78.1 MBPD in the ozone 8 hour non‐attainment (NATN) area and 18 MBPD outside of
the non‐attainment area. The total gasoline demand in Western Colorado and Southeastern
Colorado is roughly 16 and 24 MBPD, respectively.

EXECUTIVE SUMMARY
STATUS AND OPERATION OF THE COLORADO PRODUCT SUPPLY NETWORK
The Colorado Front Range is primarily supplied by six refineries – one in state (Suncor) and five
(ConocoPhillips Borger, Frontier El Dorado, Frontier Cheyenne, Sinclair Rawlins and Valero McKee)
out of state that supply the Front Range via five refined product pipelines. These refineries and
product pipelines are shown in Figure ES‐3.
ID
Salt Lake
City
UT
Figure ES‐3
Refined Product Supply – Pipelines and Refineries
Rocky Mountain Region and Colorado Front Range
Major Terminals
Refineries
(xx) Pipeline Capacity MBPCD
*
Boise
Primary Colorado Front Range Supply Refineries
Suncor Commerce City, CO
Frontier Cheyenne, WY
•Sinclair Rawlins, WY
•Frontier El Dorado, KS
•ConocoPhillips Borger, TX
•Valero McKee, TX
Missoula
Twin Falls Pocatello
Great Falls
Billings
WY
Copyright ©: EAI, Inc., 2011
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DENVER NFR FUELS SUPPLY COSTS AND IMPACTS 2011
ES‐4
MT
Rock Springs
CO
Sheridan
Casper
*
Denver
*
Fountain
Glendive
DS**
Valero McKee
*
*
La Junta
Sidney
*
WRB Borger
North
Platte
Kaneb (21)
With the exception of small truck movements of gasoline into the state from surrounding states,
almost all of the gasoline supplied to the Colorado market is delivered to the Front Range product
terminals and distributed from there to outlying areas. Ethanol supply for the Colorado market is
trucked or railed into the Denver area terminals and then blended into gasoline product. A
summary of gasoline and total product supply sources to the Colorado/Front Range market along
with pipeline capabilities is provided in the following table.
*

EXECUTIVE SUMMARY
COLORADO FRONT RANGE SUPPLY, DEMAND AND LOGISTICS
REFINED PRODUCT BALANCE
DEMAND COMPONENTS GASOLINE
TOTAL
PRODUCT
EST SEASONAL
VOLUME
PIPELINE
CAPACITIES
OPEN CAPACITY COMMENTS
Consumption 139516 212286
Truck Exports 750 750 Estimated
TOTAL DEMAND
SUPPLY COMPONENTS
140266 213036
Refinery Production 46100 77600 Suncor Refinery‐‐EAI, Inc,. Model Output
Ethanol 9533 9533 Local Truck plus rail from MW/MC
Chase Pipeline from KS 14900 36100 41154 60000 18846 One Main Source/Jet Growing
ConocoPhillips PL from Borger 18000 27200 31008 42000 10992 WRB can shift from oth mrkts
NuStar PL from Sunray ‐ Note 1 15600 22310 25433 38000 12567 Valero can shift from oth mrkts
Denver Products PL from Rawlins 11900 14000 15960 20000 4040 Potential to shift vlm to LV/SLC
Plains PL from Cheyenne 19600 20600 23484 54000 30516 Incremental supply limited
Other 3125 4032
TOTAL SUPPLY 138758 212875 137039 214000 76961 Effective Capacity in range of 40‐45 MBD
%BALANCE CLOSURE 98.92% 99.92%
The Suncor refinery is the largest source of supply to the Colorado market and two refineries,
Frontier Cheyenne and Sinclair Rawlins, place a large portion of their gasoline product into the
Front Range. The other refineries supply a smaller fraction of their total gasoline production to
Colorado, i.e. produce significant volumes of gasoline and supply these volumes to other markets.
Product pipelines also figure prominently into the Colorado Front Range gasoline supply. Besides
gasoline, these pipelines also provide a significant fraction of the state’s jet fuel and distillate fuel
supply, 77 percent and 43 percent respectively. Total capacity of the product pipelines into
Colorado is 214 MBPD and on an annual average basis 90 MBPD of open capacity existed in 2009 or
77 MBPD on a peak seasonal basis. It is important to note that several product pipelines are
connected to upstream refineries that have limited excess or swing capability generally and most
likely will have even less excess capability to make the more stringent specification product. The
effective capacity of the pipeline network to supply Denver area non‐attainment grade gasoline is
in the range of 40 to 45 MBPD. The status of the combined portions of the product supply network
for Colorado is summarized in Figure ES‐4 and the market share position of refiners in the Denver
Front Range market is shown in Figure ES‐5. As shown, the six primary supply refineries have a 92
percent share or the gasoline market. Those with the highest market share position and least
alternative market options will have the greatest probability to product gasoline to satisfy the
Denver Front Range ozone fuel specification. This would include the Suncor‐Commerce City and
Frontier‐Cheyenne refineries which have the highest market shares and the least alternative
markets options. Together they represent at least 50 percent of the market plus additional share
to account for the ethanol they use in the market.
EAI, INC. (ENERGY ANALYSTS INTERNATIONAL) EAI, INC.
DENVER NFR FUELS SUPPLY COSTS AND IMPACTS 2011
ES‐5

EXECUTIVE SUMMARY
Colorado Light Product Supply Chain
and Capacities, 2009 MBPD
The refining, light product transport and terminaling supply chain servicing the
Colorado market is a relatively tight system. Loss of product such as gasoline is not
easy to replace currently and will be even more difficult as the Front Range diverges
from other nearby market specifications.
Refining Access & Capacities
CHS Laurel, MT
ConocoPhillips Billings, MT
Little America Casper, WY
Frontier Cheyenne, WY*
Frontier El Dorado, KS*
Sinclair Rawlins, WY*
Sinclair Denver, CO*
Valero McKee, TX*
WRB Borger, TX*
9 Refineries can and have
accessed the Denver market and
*6 on a regular basis
Total Capacity 775 MBPD
Effective Refining Capacity
accessing the Colorado Front
Range Market = 673
MBPD
Refining Capacity Serves Other Markets in
other Rocky Mountain states, Midcontinent,
Texas and Midwest markets.
Figure ES‐4
Pipeline and Terminal Network has
Limited Excess Capacity ‐
Chase, COP, NuStar, Plains, Sinclair
Total Pipeline Capacity =
214 MBPD; 58% Utilized
Effective Pipeline Open
Capacity Long Term Basis
Avg. Annual = 90 MBPD
Summer = 77 MBPD
Effective Pipeline Open
Capacity Short Term Basis
Avg. Annual = 45 MBPD
Summer = 40 MBPD
Upstream pipeline bottlenecks
Seminoe pipeline from Billings to Casper
Magellan Chase –El Dorado tankage
Copyright ©: EAI, Inc., 2011
Copyright ©: EAI, Inc., 2011
EAI, INC. (ENERGY ANALYSTS INTERNATIONAL) EAI, INC.
DENVER NFR FUELS SUPPLY COSTS AND IMPACTS 2011
ES‐6
Colorado
Consumption
Total Light Product = 211 MBPD
Total Gasoline = 137 MBPD
Limited amount of effective refining
capacity that can access the Denver
Front Range Market directly via
pipeline; on the order of 100 MBPD
total product or 50 MBPD of
gasoline
Figure ES‐5
Gasoline Supply Share By Refiner: Colorado Front Range
Suncor has the largest Front Range market share with its local refinery presence followed by Frontier, WRB
(ConocoPhillips-Cenovus), Valero and Sinclair.
Frontier_Chyn,
15.8%
Sinclair, 7.2%
Frontier_Eldr,
11.1%
Others, 1.3%
Valero, 10.9%
Ethanol Plants,
6.9%
Suncor , 34.1%
WRB, 12.9%

IMPACT OF GASOLINE SPECIFICATION CHANGES
EXECUTIVE SUMMARY
EAI, Inc. via refinery modeling of the primary refineries involved in supplying the Colorado Front
Range market evaluated the changes in production costs associated with the four prospective
summer gasoline specifications. As input to this process, EAI, Inc. also surveyed a limited number
of refiners as to specifics of their capabilities. The results are summarized in the following.
Refinery Impacts: Refiners will realize ozone fuel attainment program impacts in two major ways;
1) most refiners will have to modify their refineries to make the various fuels being considered, and
2) most refiners will incur reductions of gasoline available for the Front Range market through light
ends rejection and/or shift of gasoline to other markets.
Modification/Implementation Schedule: Refiners will require 36 to 48 months to implement
capabilities to produce 7.8 no waiver and 7.0 psi‐with waiver CBOB gasoline and 60 months for the
7 psi‐no waiver or RFG gasoline grades.
Basis for Total Incremental Production Costs: The average program costs per gallon include
estimates of incremental operating costs, incremental capital costs and lost value for shifting
refinery light ends from a higher value gasoline market option to a lower value Conway natural
gasoline market.
Total Cost Impact: Total average weighted incremental production costs range from 11 to 19 CPG
with the summer RFG case being the highest and the 7.0 psi with waiver and the 7.8 psi with no
waiver the lowest at 11.4 and 12.3 CPG respectively.
The range of costs for the most realistic representation of refinery response was as follows:
o 7 psi with Waiver: The costs representing the majority of the non‐attainment area
gasoline volume was in the range of 9 to 13 CPG. This includes a high of 2 CPG for
incremental operating costs, 8 to 14 CPG for light‐end rejection and capital costs
ranging from 0.7 to 2.2 CPG of output (based on amortizing capital costs over 20
years).
o 7.8 psi with No Waiver: At 12.3 CPG total weighted manufacturing cost, this fuel
scenario was very close to the 7 psi case with waiver since the required gasoline psi
level is fairly close. Most of the additional cost for the 7.8 case was for additional
light ends rejection.
o 7 psi – No Waiver: The costs representing the majority of the non‐attainment area
gasoline volume was in the range of 2 to 24 CPG. This includes a high of 2.8 CPG for
incremental operating costs, 1 to 18 CPG for light‐end rejection and capital costs
ranging from 1 to 4.4 CPG of output (based on amortizing capital costs over 20
years). It should be noted that the total capital costs for this case were relatively
high but the investment increased the usage of light ends thus lowering the light
end rejection penalty.
EAI, INC. (ENERGY ANALYSTS INTERNATIONAL) EAI, INC.
DENVER NFR FUELS SUPPLY COSTS AND IMPACTS 2011
ES‐7

EXECUTIVE SUMMARY
o RFG Case: This was the highest cost case in terms of capital expenditures, light end
rejections and incremental operating costs with a range of 13 to 26 CPG for the
largest volume suppliers. Some of the refiners having much smaller presence in the
non‐attainment area had costs in the 1 to 1.5 CPG range.
A comparison of the manufacturing costs for the prospective gasoline grades is shown in Figure
ES‐6.
Cost, CPG
Figure REF‐6
Manufacturing Cost Increases Due To Fuels Specification
Changes: Production Weighted Cost Composite for Primary
Refineries Supplying Denver‐Front Range
20.00
18.00
16.00
14.00
12.00
10.00
8.00
6.00
4.00
2.00
0.00
Capital Costs Operating Costs C5/C6 Reject
Copyright ©: EAI, Inc., 2011
Capital Cost Impacts: Total industry capital costs to comply with the various gasoline grades being
considered is in the range of $250 million for the CBOB 7 psi with waiver and CBOB 7.8 psi no
waiver cases, $560 million dollars for CBOB 7 psi no waiver case and $710 million dollars for the
RFG case. No costs for benzene extraction or saturation are included. Capital costs are highly
variable depending on the individual refinery considered. Suncor has the highest capital costs due
to need to construct an olefin aklylation unit to replace current olefin polymerizaton units.
Operating Cost Impacts: The lowest average incremental operating costs are for the CBOB 7 psi‐
EAI, INC. (ENERGY ANALYSTS INTERNATIONAL) EAI, INC.
DENVER NFR FUELS SUPPLY COSTS AND IMPACTS 2011
ES‐8

EXECUTIVE SUMMARY
with waiver and 7.8‐no waiver cases and range from 0.15 and 2 cpg and the highest were estimated
for the 7 psi‐no waiver and RFG cases and range from 3 to 4 cpg respectively.
Lost Light End Value: The lost value for rejected light ends was estimated by EAI, Inc. The lost value
ranged from 4 cpg to 11 cpg depending on the gasoline specification being considered. This lost
value estimate is based on separating 8 to 13 MBPD of light ends at the refinery and transporting
the material to the Conway natural gasoline market. Figure ES‐7 below:
Figure ES‐7
Front Range Light End Rejection to Meet RVP & 1 lb Waiver Options
The light end rejection requirements to meet the most stringent RVP option would be on the order of 13 MBPD representing
14 percent of the overall non-attainment pool including spill over volume. This would have to be replaced with other
streams that have lower RVP levels but also can help the overall gasoline pool meet other specifications such as octane
level, drivability index, T50, etc.
Rejected Gasoline, MBPD
14.00
12.00
10.00
8.00
6.00
4.00
2.00
0.00
No Butanes 7.8_w_wvr 7.8_wo_wvr 7.0_w_wvr 7.0_wo_wvr
Lost LSR/Isomerate For NATNM Gasoline Lost LSR/Isomerate For NATNM Plus Spillover Gasoline
Copyright ©: EAI, Inc., 2011
Impact on Supply Options: Some of the proposed new fuels in the Colorado Front Range will most
likely sever supply linkage with refiners north of Cheyenne and refiners east and south of El
Dorado, Kansas. There appears to be sufficient open pipeline capacity accessing the Texas
Panhandle and Midcontinent area refiners to bring in supplemental or replacement supply.
However, these potential incremental supply sources have different combinations of RVP and/or
octane specifications then the cases being considered for Denver. The more stringent fuel
specifications are likely to make the Denver/Front Range somewhat of a market island during the
early stages of the program with potential for significant pricing upsets. Longer term, with other
markets declining and Denver retaining a premium value to these alternative markets, it is likely
EAI, INC. (ENERGY ANALYSTS INTERNATIONAL) EAI, INC.
DENVER NFR FUELS SUPPLY COSTS AND IMPACTS 2011
ES‐9
25.0%
20.0%
15.0%
10.0%
5.0%
0.0%

EXECUTIVE SUMMARY
that external sources of supply will target additional volume for the Denver‐Front Range market.
Potential Supply Loss: The Colorado Front Range is likely to experience a decline in available
gasoline supply from current supply sources due to two major factors:
Rejection of light ends (butanes & pentanes plus) to meet gasoline pool RVP limits.
This volume is estimated to be in the range of 11 to 14 MBPD. A portion of this may
be covered by increased ethanol blending either from ethanol blended into gasoline
that is not blended now or via an increase in allowable ethanol blends, e.g. E15,
increasing crude runs and/or producing other gasoline blendstocks such as
isomerate and alkylate that would allow the use of greater quantities of lighter
blendstocks.
Some refiners have access to other markets and may shift gasoline to these markets
to avoid the required capital investments in manufacturing some of the more
stringent gasoline specs being considered for the Colorado Front Range market.
The range of potential gasoline loss due to market shift is 10 to 17 MBPD with the
higher end of the range representing the RFG and 7 psi‐no waiver cases.
The combined potential loss of 20 to 30 MBPD of gasoline supply for the Front Range market may
be difficult to replace from current sources. The likely risk volume to be lost during the early stages
of the program is in the range of 10 to 15 MBPD.
Supply Availability and Impact on Market Prices: EAI, Inc.’s analysis indicates that there have often
been 2 to 21 CPG market premiums paid for 7.0 low RVP fuels (Detroit and Kansas City) relative to
conventional fuels without imposing the “1 psi no‐waiver” restriction. The Front Range market
already experiences short term, summer price increases (relative to Gulf Coast spot) and these are
likely to increase. The Denver Front Range market is more isolated than these other markets and is
likely to experience at least these levels of price increases related to the incremental cost of
gasoline meeting the new specifications. Generally the highest cost source of incremental volume
required by the market sets the market clearing price. If there is considerably more supply than
what the market can consume, prices will gravitate downward driven by surplus product spilling
over into the attainment markets.
Retail Pricing Response to Increasing Wholesale Prices: With supply being generally tight during
the early stages of the program (first two to three years), it is likely that the incremental wholesale
gasoline costs will be supported by the retail sector and passed on to the consumer. Some of the
wholesale price increase could be mitigated somewhat by competing forces at the retail level as
operators stay competitive to maintain store traffic and in‐store sales. This is especially true in
markets that have a relatively high population of hypermart stores selling gasoline as does the
EAI, INC. (ENERGY ANALYSTS INTERNATIONAL) EAI, INC.
DENVER NFR FUELS SUPPLY COSTS AND IMPACTS 2011
ES‐10

Denver market.
EXECUTIVE SUMMARY
Supply Response to Higher Prices: Preliminary estimates indicate that the current Denver – NFR
market is oversupplied with 7.8 psi gasoline with overflow occurring to the nearby attainment
market areas. With the higher cost product relative to 9.0 psi gasoline, i.e. 7.0 psi and RFG
gasolines, refiners will seek to minimize C5/C6 losses and supply only the required amount of
nonattainment area gasoline, i.e. gasoline produced for the non‐attainment areas will only be
supplied in the non‐attainment areas and conventional gasoline will be supplied in the attainment
areas, e.g. see Figure ES‐8. This will require construction of tankage at pipeline terminals to
accommodate both 9 psi gasoline and the new lower RVP products.
Figure ES‐8
Movement of Gasoline Into Attainment Areas
Lower RVP gasoline, 7 psi CBOB no waiver and RFG, will cause retraction of
non-attainment gasoline that currently moves into attainment areas.
SUPPLY ENVELOPE
NE_FRNGE
NE_REMOTE
NNATNM
NW_WY_SRCE
SE_FRNGE
SE_REMOTE
SOTHN_ACCESS
WSTR_REMOTE
WSTR_TRNS
17.6 WSTR_REMOTE
1.1 NW_WY_SRCE
9.9 WSTR_TRNS
Copyright ©: EAI, Inc., 2011
EAI, INC. (ENERGY ANALYSTS INTERNATIONAL) EAI, INC.
DENVER NFR FUELS SUPPLY COSTS AND IMPACTS 2011
ES‐11
78.1 NNATNM
3.0 NE_FRNGE
0.8 SE_FRINGE
1.0 NE REMOTE
1.2 SE_REMOTE
Ethanol Blending: Due to the Federal mandated Renewable Fuels Standards, mandated blending of
biofuels is on a course of constantly increasing requirements for ethanol blending. While there has
been some relief from blending due to small refiner exemptions, these end in 2011 with the
expected impact of requiring that the Colorado market become 100 percent ethanol blended fuels
– up from 68 percent in 2009. RINS values are expected to increase substantially when this occurs.
Since bottoming out in 2009, crude prices have recovered to the 80 – 90 $/Bbl range. At this crude

EXECUTIVE SUMMARY
price level, Gulf Coast spot market clear gasoline has ranged from 195 to 222 cents per gallon while
spot ethanol prices have been in the 168 to 245 cents per gallon range. At these pricing levels
combined with the ethanol blenders tax credit, ethanol blending can act to lower gasoline
production costs and these savings may be passed on to the consumer.
Boutique Gasoline Products and Fungability: In the near term, more ozone non‐attainment
markets are expected to adopt low RVP gasoline “standards”, this product will be in greater supply
and accessible to markets from more refinery options. In the last two years, the number of
metropolitan areas requiring 7.8 RVP gasoline has increased to 19 while the number of
metropolitan areas that require 7.0 RVP gasoline has stayed constant at 5 (Atlanta, Birmingham, El
Paso, Kansas City and Detroit). Similarly, no new RFG mandated areas have been added. It is
important for states and local governments to work in tandem to adopt common standards that
recognize not only the localized market but the overall capability of the fuel supply chain. Other
near term potential ozone non‐attainment markets are Salt Lake City, Tulsa, Oklahoma City and
Wichita.
Further Federal Environmental Mandates: In the near term (beginning in 2011 and becoming
more stringent in 2012), refiners have to meet more strict limitations on benzene levels in gasoline
under MSAT. Most of the major suppliers of gasoline to the Colorado Front Range can either meet
these specifications or are in the process of installing equipment/changing operations to meet the
new regulations. With the required benzene reductions coupled with lower gasoline RVP
requirements, there is some convergence of the lower RVP gasoline option and RFG and their
respective properties.
EAI, INC. (ENERGY ANALYSTS INTERNATIONAL) EAI, INC.
DENVER NFR FUELS SUPPLY COSTS AND IMPACTS 2011
ES‐12

OV
OVERVIEW OF THE COLORADO AND
FRONT RANGE FUELS MARKET
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DENVER NFR FUEL SUPPLY COSTS – IMPACTS 2011

OVERVIEW OF THE COLORADO AND FRONT RANGE FUELS MARKET
INTRODUCTION
The Colorado and the Front Range fuel markets are dynamic, complex, and interlocked markets
that form a distinct market in the Midcontinent ‐ Rocky Mountain area. They are isolated markets,
physically separated from other surrounding major markets, such as Kansas City and Salt Lake City,
and especially the large Gulf Coast refinery distribution system. Like other isolated central U.S.
markets, the Colorado and Front Range fuel markets depend on outside suppliers to provide a
substantial portion of the required fuel products consumed in the area.
Six major refineries and five major product pipelines supply this area. Other swing refineries and
ancillary pipelines are capable of providing some additional product. Five of these refineries are
located out‐of‐state, with the sixth, the Suncor refinery, is located in Commerce City. The local
Commerce City refinery is the largest single supplier to the Colorado and Front Range Markets,
supplying roughly one‐third of the Front Range area’s product. Of the other five refineries, two,
both in Wyoming are also primarily oriented to supplying the Front Range market. The other three,
two in Texas, and one in Kansas supply products to multiple markets, with the Colorado/Front
Range markets being only one of their major markets. These refineries have the ability to move
product to the markets that are most attractive business‐wise.
Because of past ozone violations, the Denver area has been designated as a low summertime
gasoline volatility area, with base gasoline having a maximum Reid Vapor Pressure (RVP) of 7.8
pounds per square inch (psi). With the adoption of the current eight‐hour ozone State
Implementation Plan (SIP), this area was recently expanded to include the entire seven county
Denver metropolitan area, as well as to parts of Larimer and Weld counties that are contained in
the ozone nonattainment area. Outside of the Denver/North Front Range areas, a more volatile
summertime gasoline of up to 9.0 lbs. RVP is permitted.
The Denver – Boulder – Greeley – Fort Collins eight hour ozone control area (ozone non‐
attainment) is shown in Figure OV‐1. This area encompasses major portions of the Colorado Front
Range and includes both major populated areas (Denver, Boulder, Fort Collins, Castle Rock and
Greeley) and also a larger control area that includes areas of eastern, northeastern and northern
Colorado. Counties included in this area are Adams, Arapahoe, Boulder, Broomfield, Denver,
Douglas, Jefferson, Larimer and Weld.
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OV‐1

OVERVIEW OF THE COLORADO AND FRONT RANGE FUELS MARKET
Figure OV‐1
Denver-Boulder-Greeley-Fort Collins
Eight Hour Ozone Control Area
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DENVER NFR FUEL SUPPLY COSTS – IMPACTS 2011
OV‐2
Copyright ©: EAI, Inc., 2011
Location of this nine county area within the existing gasoline distribution areas of Colorado is
shown in Figure OV‐2. As shown, the nine county ozone non‐attainment area is entirely located
within EAI, Inc.’s defined Denver Front Range market area. Other gasoline market areas in
Colorado include the Colorado Springs – Pueblo market area to the south and the Grand Junction –
Western Slope market area to the west.
GASOLINE DEMAND IN COLORADO
Gasoline demand in Colorado in 2009 was estimated to have been 136.8 thousand barrels per day
(MBPD). This overall demand may be further split into different regions of Colorado to represent
local markets.
In the Denver Front Range area, gasoline demand was estimated to be 96.0 MBPD in 2009. This
includes gasoline demand within the Denver Front Range area from areas outside of the eight‐hour
ozone nonattainment area. Within the ozone nonattainment area proper, gasoline demand is
estimated to be 78.1 MBPD.
Outside of the Denver Front Range market area, EAI estimates that there is a total fuel demand of
40.8 MBPD. This split between southern and southeastern Colorado markets and Western Slope
markets. Including the 17.9 MBPD of 9.0 lb RVP conventional gasoline that can be sold in the
Denver Front Range area, and the 40.8 MBPD of 9.0 lb. RVP conventional gasoline that may be sold

OVERVIEW OF THE COLORADO AND FRONT RANGE FUELS MARKET
in Colorado areas outside of the Denver Front Range area, a total market demand of 58.6PD of 9.0
lb. RVP conventional gasoline may is estimated. This compares to the estimated 78.1 MBPD market
demand for 7.8 lb RVP low volatility gasoline that is required in the eight‐hour ozone
nonattainment area. However, fuel sampling by the Colorado Department of Public Health and
Environment shows that the overwhelming majority of Front Range gasoline from Pueblo to the
Wyoming border is blended at the 7.8 lb. RVP level, regardless of whether the area is located in a
conventional 9.0 lb RVP area, or the 7.8 lb. Low RVP area. It is thought that fuel storage tank
constraints and the ability to provide excess 7.8 lb. RVP product is responsible for this situation.
Under different marketing conditions and fuel requirements this situation could change. EAI, Inc.
has used its own proprietary models in estimating market demands in this Micro‐Market Demand
analysis.
Figure OV‐2 diagrams this fuel market demand, with the nine county Denver Front Range market
area shown in green. Red boundaries indicate the boundaries of the principal fuel market areas in
Colorado as used by EAI, Inc. in their fuel demand analysis. The 96.0 MBPD Denver Front Range
market area is primarily supplied by the local Commerce City refinery and the major product
pipeline terminals in the Denver area. There are also minor truck volumes that enter this area from
Rawlins and Cheyenne, Wyoming and from Phillipsburg, KS.
MINERAL
RIO GRANDE
ALAMOSA
ARCHULETA
CHAFFEE
Figure OV‐2
Gasoline Demand Distribution
Colorado by Geography and Ozone Attainment Status, 2009
Total Gasoline Demand at 136.8 MBPD
Western CO
Demand = 16
MBPD
MESA
DELTA
GRAND JUNCTION
MONTROSE
DOLORES
MONTEZUMA
MOFFAT
RIO BLANCO
GARFIELD
MARKET
WESTERN SLOPE
OURAY
SAN MIGUEL
LA PLATA
HINSDALE
ROUTT
PITKIN
GUNNISON
EAGLE
JACKSON
LAKE
GRAND
SAGUACHE
CONEJOS
LARIMER
GILPIN
BOULDER
CLEAR CREEK
PARK
JEFFERSON
FREMONT
CUSTER
COSTILLA
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DENVER NFR FUEL SUPPLY COSTS – IMPACTS 2011
OV‐3
DENVER
ADAMS
DOUGLAS
TELLER
HUERFANO
WELD
ARAPAHOE
EL PASO
PUEBLO
COLO SPR – PBLO
MARKET
ELBERT
LAS ANIMAS
MORGAN
LINCOLN
CROWLEY
OTERO
LOGAN
DENVER
FRONT RANGE
MARKET
WASHINGTON
BENT
KIT CARSON
CHEYENNE
KIOWA
SEDGWICK
BACA
PHILLIPS
YUMA
Denver-Front Range
Demand
Ozone NA = 78 MBPD
Ozone ATN = 18 MBPD
Southeast CO
Demand = 24
PROWERS
MBPD
Copyright ©: EAI, Inc., 2011

OVERVIEW OF THE COLORADO AND FRONT RANGE FUELS MARKET
The Denver Front Range area dominates the entire Colorado market, with less of a gasoline
demand in the rest of the state. EAI, Inc. estimates that the Grand Junction – Western Slope
market area and the Colorado Springs – Pueblo market areas is roughly 16.5 and 24.3 MBPD,
respectively. The southern Colorado market is supplied from the Fountain and La Junta product
terminals, as well as from Denver (especially Colorado Springs). The Grand Junction – Western
Slope area is generally supplied by rail and truck from Denver, as well as some product from
western Wyoming and Utah. The four corners area is supplied to a large extent from New Mexico.
Jackson County is generally supplied from sources in Wyoming. Figure OV‐2 shows these areas.
Overall gasoline demand has been relatively flat over the last five years with some indications of a
demand slump in 2008 and 2009. This is despite a significant increase in vehicle miles traveled
(VMT) over the early part of this period.
The Colorado Department of Revenue tracks the use of fuel ethanol in the state of Colorado.
According to their figures, the percentage of ethanol blended gasoline utilized for 2009 is 68
percent of total gasoline distributed. This figure is disputed by the Colorado Department of Public
Health and Environment which conducts a biannual fuel survey in the Front Range area. CDPHE
believes that based on their fuel surveys, the total amount of ethanol blended gasoline is
underreported by industry, with much of the ethanol blended gasoline reported as non‐blended
gasoline to the Department of Revenue. For Colorado tax purposes, it does not matter if gasoline is
reported as ethanol blended or non‐blended gasoline.
Using the CDOR figures, total year 2009 estimated ethanol blended into gasoline is 9.53 MBPD
assuming a ten percent blend. A 2009 summer survey of retail gasoline samples performed by the
Colorado Department of Public Heath and Environment, indicates that ethanol blended gasoline
comprised 95 – 98 percent of the Colorado Front Range gasoline that summer. This would
indicate that if the ethanol blended gasoline market share were applied statewide, up to 13.95
MBPD of fuel ethanol was used.
A five year history of gasoline consumption in the state of Colorado is presented in the table below.
Colorado Gasoline Consumption Trends
Units: BPD 2005 2006 2007 2008 2009
Gasoline 75367 84995 74495 52143 44186
Gasohol 65848 55706 66899 86588 95330
Total 141215 140701 141395 138731 139516
Ethanol Blended Calculated * 6585 5571 6690 8659 9533
Percent Ethanol Blended Gasoline * 46.60% 39.60% 47.30% 62.40% 68.30%
Source: Colorado Dept of Revenue ‐ Gross Gallons
* Colorado Dept of Revenue figures generally low, see following text
Gasoline demand in Colorado is seasonal. As shown in Figure OV‐3, gasoline demand peaks in the
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DENVER NFR FUEL SUPPLY COSTS – IMPACTS 2011
OV‐4

OVERVIEW OF THE COLORADO AND FRONT RANGE FUELS MARKET
summer, when gasoline demand is greatest, and lowest during the winter months, when gasoline
demand is least. Summer months register gasoline demand that is typically 107 to 110 percent of
the yearly average. This compares to the winter months when gasoline demand at its lowest, of
around 93 percent of the annual average volume.
Summer peak gasoline demand in 2009 was about 152.9 MBPD. This compares to the average
annual demand of 139.5 MBPD from the Department of Revenue. The fuel distribution network in
Colorado is thus most highly utilized during the summer months when gasoline most in demand.
Fortunately, Colorado has experienced few fuel disruptions that have affected the motoring public,
though events such as the shutdown of the Valero McKee Texas plant closure in February 16, 2007,
due to a catastrophic fire starting in the propane de‐asphalting unit, came close to producing a
major dislocation of the Colorado fuel market with localized fuel shortages through the spring and
summer of 2007. There was some fuel rationing to service stations that resulted in certain fuel
dispensing units running out of product. Figure OV‐3 shows the monthly fuel demand in Colorado
as compiled by the Colorado Department of Revenue.
Figure OV‐3
Seasonality of Colorado Gasoline Demand
Calculated as monthly gasoline demand BPD divided by annual average gasoline
demand BPD. Seasonal maximum in summer at 1.07 to 1.1 times annual average.
Seasonal low generally in January at 0.93 times annual average.
Monthly Volume/Annual Average
1.15
1.1
1.05
1
0.95
0.9
0.85
0.8
JANUARY
FEBRUARY
2005 2006 2007 2008 2009
MARCH
APRIL
MAY
JUNE
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DENVER NFR FUEL SUPPLY COSTS – IMPACTS 2011
OV‐5
JULY
AUGUST
SEPTEMBER
OCTOBER
NOVEMBER
DECEMBER
Copyright ©: EAI, Inc., 2011
EAI, Inc.’s forecast for gasoline consumption in Colorado is for gasoline demand, shown in Figure
OV‐4, to recover in 2010, remain basically flat until 2013 and then undergo a long period of slow

OVERVIEW OF THE COLORADO AND FRONT RANGE FUELS MARKET
decline with forecasted demand levels of 135 MBPD in 2020 and 123 MBPD in 2030. The primary
driver for the decline in gasoline is the mandated increase in new vehicle miles per gallon rating
which will start showing a large impact after 2020. Another important driver of the gasoline
demand forecast is a decline in the driving age population associated with aging of the population.
150
140
130
120
110
100
Figure OV‐4
Annual Colorado Gasoline Demand
Actual and Forecast through 2030 (in MBPD)
2009
2008
2011
2014
2017
EAI, INC. (ENERGY ANALYSTS INTERNATIONAL) EAI, INC.
DENVER NFR FUEL SUPPLY COSTS – IMPACTS 2011
OV‐6
2020
COLORADO FRONT RANGE GASOLINE SUPPLY STRUCTURE
2023
2026
2029
Copyright ©: EAI, Inc., 2011
Colorado is part of the Rocky Mountain supply network. As shown in Figure OV‐5 the Rockies are
relatively isolated in terms of multiplicity of supply sources compared to other regions of the
country. This isolation takes a number of forms – limited number, capacity and capability of
refineries that actually can supply the market, limited number and capacity of product pipelines
that supply the market, and differences in gasoline product supply specifications of the Colorado
Front Range market versus outlying markets. As implied by Figure OV‐5, it is possible for refined
products sourced in the Gulf Coast (Houston‐Beaumont‐ Port Arthur area) to be transported via
pipeline to the Colorado Front Range but this is generally not the case as supply can be provided by
more closely located refineries. However, if needed and the pipeline capacity is available, this can

OVERVIEW OF THE COLORADO AND FRONT RANGE FUELS MARKET
be accomplished via shipping on Explorer or Magellan pipelines to the Tulsa area, then on Magellan
pipeline from Tulsa to Wichita – El Dorado, KS and then on Magellan Chase pipeline from El Dorado
to Aurora, CO.
Figure OV‐5
U.S. Refined Product Supply-Demand Network
Definition of EAI, Inc. U.S. Product Distribution Hubs and Regions
The Rocky Mountain petroleum market is one of the most isolated areas in the U.S.
Pacific
Southwest
Refining center
Primary pipeline
Product import
Vessel movement
Rocky
Mountain
Gulf Coast
EAI, INC. (ENERGY ANALYSTS INTERNATIONAL) EAI, INC.
DENVER NFR FUEL SUPPLY COSTS – IMPACTS 2011
OV‐7
Northern
Tier
Midcontinent
Midwest
Southeast
Seaboard
Copyright ©: EAI, Inc., 2011
Historically, shipments of product from the Gulf Coast – Midcontinent to Colorado have been
limited to jet fuel due to the pipeline bottlenecks or because the existing sources have been able to
supply the required gasoline and distillate products. As a generality, the Colorado and the Rocky
Mountain region market may use lower octane gasoline than outside markets due to the higher
altitude, i.e. supplying Gulf Coast or Midcontinent grade gasoline would result in octane giveaway.
Suppliers generally get around this problem by exchanging Gulf Coast or Midcontinent grade
gasoline for Denver grade gasoline with Frontier El Dorado refinery.
A more detailed view of the refined product supply network for the Rocky Mountains and the
Colorado Front Range is shown in Figure OV‐6. There are six primary refineries supplying the
Colorado Front Range market. The Suncor refinery at Commerce City CO is the only refinery
directly located in the Front Range. The WRB (Cenovus‐ConocoPhillips) refinery at Borger TX
supplies the market via its 42 MBPD capacity ConocoPhillips pipeline. The Valero refinery at McKee
TX supplies the market through the 38 MBPD NuStar product pipeline, as well as supplying
Colorado Springs and southern Colorado. The Frontier refinery at El Dorado KS supplies the market
via the 60 MBPD capacity Chase pipeline owned by Magellan. The Frontier refinery at Cheyenne

OVERVIEW OF THE COLORADO AND FRONT RANGE FUELS MARKET
WY supplies the Front Range via the 54 MBPD capacity Plains Kaneb pipeline. Finally, the Sinclair
refinery at Rawlins, WY supplies the Front Range via its Denver Product pipeline which has a
capacity of 20 MBPD.
Salt Lake
City
Figure OV‐6
Refined Product Supply – Pipelines and Refineries
Rocky Mountain Region and Colorado Front Range
Major Terminals
Refineries
(xx) Pipeline Capacity MBPCD
*
ID
Boise
Primary Colorado Front Range Supply Refineries
Suncor Commerce City, CO
Frontier Cheyenne, WY
•Sinclair Rawlins, WY
•Frontier El Dorado, KS
•ConocoPhillips Borger, TX
•Valero McKee, TX
Missoula
Twin Falls Pocatello
UT
Great Falls
Billings
WY
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DENVER NFR FUEL SUPPLY COSTS – IMPACTS 2011
OV‐8
MT
CO
Sheridan
Rock Springs
Casper
*
Denver
*
Fountain
Glendive
DS**
Valero McKee
*
*
La Junta
Sidney
North
Platte
Kaneb (21)
*
WRB - ConocoPhillips Borger
*
Copyright ©: EAI, Inc., 2011
It is possible for the Sinclair Little America refinery at Casper WY and the three Billings area
refineries (CENEX, ConocoPhillips, ExxonMobil) to supply product to Denver via pipeline but in the
recent past relatively little of this supply interaction has taken place (around one percent of total
Colorado gasoline supply). This has been partially due to the difficulty of making Denver area
summertime specification gasoline but mostly due to tightness of product supply (and associated
higher value) in the other Rocky Mountain markets north of Colorado.
Supply volumes of the major refined products (gasoline, jet, and distillate) for the state of Colorado
are presented in Table OV‐1, presented at the end of the chapter, which is in the form of a supply –
demand balance. As shown, Suncor refinery is the primary source of gasoline in the Colorado Front
Range representing about 33 percent of gasoline supply. Other major sources of gasoline are
product pipelines, in supply share descending order, Magellan Chase pipeline from Wichita/El
Dorado, KS; ConocoPhillips pipeline from Borger, TX; Plains Kaneb pipeline from Cheyenne WY;
NuStar pipeline from McKee, TX; and Denver Products pipeline from Rawlins, WY. With the
exception of ConocoPhillips pipeline and Plains Kaneb pipeline, all of the product moving through
the product pipelines represent product manufactured at the respective upstream refinery. In the
case of ConocoPhillips pipeline from Borger, NuStar is also a 33 percent undivided interest owner in
this product pipeline and Valero McKee refinery also ships product on the ConocoPhillips pipeline.

OVERVIEW OF THE COLORADO AND FRONT RANGE FUELS MARKET
As noted above, the Plains Kaneb product pipeline has connections into product supply from the
Billings refineries and the Frontier Cheyenne refinery. Roughly 85 percent of the volumes to the
Front Range on this pipeline originate at the Frontier Cheyenne refinery. An overview of the supply
sourcing for the Colorado Front Range market is shown in Figure OV‐7.
CHEVRON
POCATELLO
RVP 7.8
PHOENIX
AZ-CBG
EVANSTON
ROCK SPRINGS
SINCLAIR
GILLETTE
CASPER
Figure OV‐7
Current Colorado Front Range Gasoline Supply Envelope
Current Summer 7.8 psi Gasoline – With Waiver
PCTL
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NEWCASTLE
CHEYENNE
OV‐9
RVP 7.8
SLC
GRAND
JUNCTION
GRAND
JUNCTION FOUNTAIN
COLORADO SPR
CHASE
SUPERIOR LINCOLN
SALINA Envelope
DELPHOS
SCOTT CITY GREAT BEND
MCPHERSON
TOPEKA
CO SPR-PUEBLO
LA JUNTA
DODGE CITY
WICHITA
EL DORADO
LAS VEGAS
BLOOMFIELD
NUSTAR COP
MEDFORD
LAVERNE
PONCA CITYTULSA
FLAGSTAFF
FLAGSTAFF
ABQ
GALLUP
ALBUQUERQUE
SANTA FE
VALERO
MCKEE
TUCUMCARI
COP
BORGER
ENID
OKLAHOMA
OKLAHOMA CITY
CITY
AMARILLO
LAWTON
REFINED
PRODUCT
TERMINAL
PRODUCTS
PIPELINE
BILLINGS
RVP 9.0
SLC
BILLINGS
CHEYENNE
CASPER
REFINERY TRUCKING
RAPID CITY
COP
Total Supply
Envelope
GRAND ISLAND
NORTH PLATTE
SIOUX FALLS
MITCHELL
DONIPHAN
ABERDEEN
YANKTON
NORFOLKSIOUX
CITY
Primary Supply
COUNCIL BLUFFS
DFW
RVP 7.8
MILFORD
Copyright ©: EAI, Inc., 2011
As noted in Table OV‐1, the total capacity of the product pipeline systems supplying the Front
Range from outside the state is approximately 214 MBPD. The available open effective annual
average capacity is estimated to be 91 MBPD though due to a number of constraints, this can be
reduced more typically at times to 28 MBPD on an annual basis and 22 MBPD in the summer. A
number product pipelines have upstream constraints in obtaining more product for the Colorado
Front Range market. The Plains Kaneb pipeline is limited in obtaining more volumes from the
Billings refineries by capacity limitations on Seminoe pipeline from Billings to Casper. As noted
above, there are constraints on the Magellan Chase system in obtaining more product from the
Midcontinent and Gulf Coast origins through El Dorado. Similarly, the NuStar and ConocoPhillips
pipelines from the Texas Panhandle are constrained either by pipeline capacity limitations and/or
operation constraints of the ConocoPhillips and Valero refineries and their supply obligations to
other markets. Regarding this last factor, there is some additional pipeline space from the Texas
Panhandle to the Colorado Front Range that could be used to “swing” product from other markets
to the Colorado market depending on relative market pricing and netback realizations.
Ethanol is a growing portion of the gasoline supply and survey responses of the major refiner –
marketers indicate that ethanol is sourced from numerous ethanol plants and marketing
companies – generally the lowest cost source. Rail receipt capability for ethanol supplies appears

OVERVIEW OF THE COLORADO AND FRONT RANGE FUELS MARKET
to be confined to the facilities at the Suncor refinery and Ethanol Management Company at
Henderson CO. Both have facilities for offloading rail cars and tank trucks and also out‐loading tank
trucks. The product pipeline terminals have truck unloading facilities.
An overview of important recent events and system constraints involving the product supply
network associated with the Rocky Mountain region is shown in Figure OV‐8. Up until the
recessionary 2008 – 2009 timeframe, the refineries supplying the Rocky Mountain region had been
at capacity in the summertime and a number of product pipelines had been operating at capacity.
One of the major impacts of the recession has been a major decline in the economy outside of the
Rockies which has translated into a drop in demand for movement of freight cargo from the West
Coast ports through rail and truck routes across the Rockies. This, plus the declines in other sectors
like mining and construction, has lead to a dramatic decline in distillate demand in all of the Rockies
states but concentrated in Wyoming. The overall result has been a cutback in crude runs at
Wyoming refineries. Attendant to the decline in refined product demand across the U.S. has been a
decline in refinery margins, leading to shutdowns of some refining capacity. One important
pipeline project that has been permitted and has been announced as moving ahead is the Holly –
Sinclair UNEV product pipeline from Salt Lake City to Las Vegas. This pipeline would prospectively
allow product from Sinclair Rawlins and Holly Woods Cross refineries to be placed into Las Vegas.
This would give Sinclair an option of not investing in projects to make more rigid Denver area ozone
non‐attainment area gasoline and instead make prospectively cheaper grades of gasoline for the
Las Vegas market.
Barge
ID
Boise
Salt Lake
City
Seasonal
Bottlenecks
Figure OV‐8
Refined Product Network Status
Rocky Mountain Region
Colorado Front Range market supplied by five product pipelines, one local refinery and ethanol
railed or trucked into the market.
SLC refineries have cut
runs by 2 MBPD.
Flying J bankruptcy.
Silver Eagle restarting.
Approval for UNEV
pipeline received – Start
up in 2Q2011.
Major Demand Centers
Major Refining Centers
High Demand Growth Areas
(xx) Pipeline Capacities in MBPD
Diesel
Missoula
Rail from Helena to
Thompson
Falls/Spokane
High Utilization WY
Casper
Wyoming refineries
have cut runs
2009 decline
by 4 MBPD
UT
Denver Products
pipeline volumes
down
Western Bloomfield NM refinery
shutdown – impacts Western Slope
supply.
MT
Billings
Billings refinery runs
maintained
EAI, INC. (ENERGY ANALYSTS INTERNATIONAL) EAI, INC.
DENVER NFR FUEL SUPPLY COSTS – IMPACTS 2011
OV‐10
CO
Suncor refinery runs
Fountain
increased in 2009
Seminoe pipeline at
capacity
Newcastle
Denver
Flint Hills expanded
Pine Bend refinery by
50 MBPD-2008
Refinery Utilization
Refineries in Colorado,
Montana , Utah and
Wyoming operating
seasonally at full capacity
Refinery supply constrained
Sinclair Built Segment to
Chase and can reverse Denver Products Pl
North Platte
Kaneb (21)
2009 gasoline demand
maintained, diesel and
jet down
Chase pipeline
deliveries
down
Potential MC refinery shutdowns
and low utilization
Copyright ©: EAI, Inc., 2011
Historically, the Western U.S. has been product short with limited access to product from the Gulf

OVERVIEW OF THE COLORADO AND FRONT RANGE FUELS MARKET
Coast or the Rockies, see Figure OV‐9. This situation changed with the expansions of the Longhorn
and Kinder Morgan East Leg pipelines and prospectively the construction of a new product pipeline
from Salt Lake City to Las Vegas by Holly and Sinclair (UNEV). As noted in Figure OV‐8, two
refineries in the Western Region have closed due to financial problems, the Flying J Bakersfield, CA
refinery and the Western Bloomfield, NM refinery. Product from the Bloomfield refinery was
trucked in to the Western Slope of Colorado. Prospectively lost product from this refinery will be
sourced from the nearby Western refinery at Ciniza and additional product moving via pipeline
from the Western El Paso refinery and the Navajo Artesia refinery into Albuquerque and Four
Corners.
Figure OV‐9
Western Region Refined Product Network
Project Updates and Key Business Drivers
The U.S. West Coast downstream business is undergoing fundamental changes
that will impact supply and logistics for the long term.
Flying J
Bakersfield
refinery idled
Tanker
Movement
Gasoline demand
declining plus etoh
supply increasing
KM was planning
expansion to 200
MBPD. Current
capacity is 157MBPD
West Coast
(mainland) foreign
imports of gasoline
peaked in 2007averaging
30 to 40
MBPD in 2008 /2009
Olympic
Pacific
Northwest
Foreign
and Gulf
Coast
Imports
Domestic gasoline
imports into LA in
60-70 range/down
from 100+ MBPD
during peak period
Holly/Sinclair
pursuing 12 in Pl
to Las Vegas:
startup 2Q2011
Pacific
Southwest
Rocky
Mountain
Bloomfield
refinery idled
Phoenix
Tucson
KM has expanded East
Line; 155 MBPD to
Phoenix & 170 MBPD
to Tucson
EAI, INC. (ENERGY ANALYSTS INTERNATIONAL) EAI, INC.
DENVER NFR FUEL SUPPLY COSTS – IMPACTS 2011
OV‐11
Silver Eagle
refinery restarted
After fire
El Paso
Gulf Coast
Gasoline surplus
growing
SUMMARY OF COLORADO MARKET SUPPLY AND DEMAND
Refining Center
Primary Pipeline
Pipeline Expansion
New Pl Project
Marine Movements
WTX-NM refiners have
crude supply/price
incentive to expand
but limited market
options
Longhorn acquired by
Magellan, currently moving
low volumes. Was
averaging 60 to 70 MBPD in
2008.
9
Copyright ©: EAI, Inc., 2011
A summary of the Colorado market supply chain and capacity considerations is presented in Figure
OV‐10. Historically nine refineries have placed gasoline product into the Colorado Front Range
market. Eight of these refineries place product in the Colorado market on a frequent basis and as
noted above only six refineries supply product to the Colorado market on an on‐going, large
volume basis. Considering the product pipeline system, the total product pipeline capacity into the
Colorado Front Range market is 214 MBPD but considering upstream refinery constraints, other
market supply obligations and current pipeline throughputs, the available additional capacity to
supply the market on a short term outage basis is estimated at 45 MBPD on an annual average

OVERVIEW OF THE COLORADO AND FRONT RANGE FUELS MARKET
basis or at 40 MBPD on a summertime basis. On a longer term basis, where decisions to vacate
supplying the Colorado market are known well in advance, the potential to supply the Front Range
market via outside product pipeline sources increases to 77 to 90 MBPD considering refiners
shifting product out of other markets and investments to relieve immediate product pipeline
constraints.
Figure OV‐10
Colorado Light Product Supply Chain
and Capacities, 2009 MBPD
The refining, light product transport and terminaling supply chain servicing the
Colorado market is a relatively tight system. Loss of product such as gasoline is not
easy to replace currently and will be even more difficult as the Front Range diverges
from other nearby market specifications.
Refining Access & Capacities
CHS Laurel, MT
ConocoPhillips Billings, MT
Little America Casper, WY
Frontier Cheyenne, WY*
Frontier El Dorado, KS*
Sinclair Rawlins, WY*
Sinclair Denver, CO*
Valero McKee, TX*
WRB Borger, TX*
9 Refineries can and have
accessed the Denver market and
6* on a regular basis
Total Capacity 775 MBPD
Effective Refining Capacity
accessing the Colorado Front
Range Market = 673
MBPD
Refining Capacity Serves Other Markets in
other Rocky Mountain states, Midcontinent,
Texas and Midwest markets.
Pipeline and Terminal Network has
Limited Excess Capacity ‐
Chase, COP, NuStar, Plains, Sinclair
Total Pipeline Capacity =
214 MBPD; 58% Utilized
Effective Pipeline Open
Capacity
Avg. Annual = 90 MBPD
Summer = 77 MBPD
Effective Pipeline Open
Capacity Short Term Basis
Avg. Annual = 45 MBPD
Summer = 40 MBPD
Upstream pipeline bottlenecks
Seminoe pipeline from Billings to Casper
Magellan Chase –El Dorado tankage.
EAI, INC. (ENERGY ANALYSTS INTERNATIONAL) EAI, INC.
DENVER NFR FUEL SUPPLY COSTS – IMPACTS 2011
OV‐12
Colorado
Consumption
Total Light Product = 214 MBPD
Total Gasoline = 137 MBPD
Limited amount of effective refining
capacity that can access the Denver
Front Range Market directly via
truck; on the order of 100 MBPD or
50 MBPD of gasoline
Copyright ©: EAI, Inc., 2011

OV‐13
Table OV-1
Colorado State Level Refined Product Balance ‐ 2009
Units: BPD
REFINED PRODUCT BALANCE
DEMAND COMPONENTS GASOLINE JET DISTILLATE TOTAL PL CAPACITIES
OPEN
CAPACITY
COMMENTS
Consumption 139516 26624 46204 212344
Truck to Utah 500 300 100 900 Estimated
Truck to New Mexico 150 0 0 150 Estimated
TOTAL DEMAND 140166 26924 46304 213394
SUPPLY COMPONENTS
GASOLINE JET DISTILLATE TOTAL PL CAPACITIES
OPEN
CAPACITY
COMMENTS
Refinery Production 46100 7000 24500 77600 Suncor refinery ‐Model Output
Ethanol 9519 0 0 9519 CO Dept of Revenue
Chase Pipeline from KS 21800 11220 1700 34720 60000 25280 Upstream constraints either El Dorado or getting Tulsa barrels in
ConocoPhillips PL from Borger 17800 7500 3490 28790 42000 13210 WRB‐COP Borger and Valero McKee refinery supplied
NuStar PL from McKee 15050 1700 6760 23510 38000 14490 Valero McKee refinery supplied
Denver Products PL from Rawlins 9909 0 4700 14609 20000 5391 Sinclair Rawlins refinery supplied
Plains PL from Cheyenne 17100 0 3500 20600 54000 33400 Frontier Cheyenne refinery and Billings refinery supplied
Truck from 4 Corners 706 0 192 898 To Western Slope
Trucks from TX 150 0 0 150 To SE Colorado
Trucks from WY 792 0 451 1243 To N. Colorado
Blending Plants 1312 0 250 1562 Western Slope
Stock Withdrawal ‐60 0 ‐644 ‐704 DOE
TOTAL SUPPLY 140178 27420 44899 212497 214000 91771
%BALANCE CLOSURE
Note 1: Based on full year 2009 information
100.01% 101.84% 96.97% 99.6% See Note 2
Note 2: Available capacity to supply market may also be reduced due to upstream pipeline deliveries, NGL's or refinery constraint
FRONT RANGE MAJOR SUPPLY SOURCES
Suncor
GASOLINE
32.9%
Chase Pipeline (Frontier El Dorado) 6.8%
ConocoPhillips (COP Borger) 15.6%
Plains Pipeline (Frontier Cheyenne) 12.7%
NuStar Pipeline (Valero McKee) 10.7%
Denver Products Pipeline (Sinclair Rawlins) 7.1%
Ethanol 12.2%
TOTAL 97.9%
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REF
REFINING AND GASOLINE SUPPLY
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INTRODUCTION
REFINING AND GASOLINE SUPPLY
In this section, the primary refineries supplying the Denver/North Front Range area are more fully
described in terms of their individual capabilities, makeup and characteristics. The secondary
refineries that have access to the Denver/North Front Range market area are also addressed and
profiled but in less detail. Each primary supply refinery is reviewed to give a description of unit
operations, the crude slates they are set up to utilize, and estimated outputs of refined products.
As background, the primary refinery units and processes are described.
There are six refineries that service the bulk of the Colorado/Front Range market. While there are
a small number of other refineries and sources for a small amount of product and individual
gasoline components, these six refineries are responsible for supplying almost all of the gasoline
product in the Front Range area, as well as the vast majority of gasoline throughout the rest of the
state. The six refineries supplying the Colorado/Front Range markets, and where they are located
are listed below:
REFINERY LOCATION
Suncor Commerce City, CO
Frontier El Dorado, KS
Frontier Cheyenne, WY
Sinclair Rawlins (Sinclair), WY
WRB Borger, TX
Valero McKee (Sunray), TX
REFINERY PROCESS UNIT AND OPERATION REVIEW
Refineries utilize a variety of operations that are used to produce finished gasoline and other
products from crude oil and other feeds and blendstocks. Depending on specifications of the
finished product, the physical setup of the refinery, and the type and quality of the crude oil used,
different interconnected operations and refinery units are emphasized. In these processes, crude
oil is separated into various cuts (boiling point ranges) that then are further refined and separated
into various refinery streams. In the case of gasoline, the finished refined components are then
blended together to produce specification grade gasoline. A generalized process flow diagram of
petroleum refining operations can be used to illustrate this process, as is shown in Figure REF‐1. A
general overview description of refinery process units follows for informational purposes. For
clarity, each of the six refineries evaluated in this study is different and none of the refineries has
all of the units described in the general listing. The major process units of the six primary supply
refineries and the four additional refineries that can access the Colorado Front Range market are
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DENVER NFR FUEL SUPPLY COSTS AND IMPACTS 2011
REF‐1

REFINING AND GASOLINE SUPPLY
listed in Table REF‐1. As noted above, each of the refineries has a different array of processing
units and has different processing capabilities.
Figure REF‐1
Generalized Refinery Process Schematic
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DENVER NFR FUEL SUPPLY COSTS AND IMPACTS 2011
REF‐2
Copyright ©: EAI, Inc., 2011
Atmospheric crude distillation tower: This unit is the primary refinery processing unit. In this unit,
crude oil is distilled and separated into various fractions by boiling range. These fractions, in order
of light density to heavy density products, include light petroleum gases, light naphtha, heavy
naphtha, jet fuel and kerosene, distillate fuel and atmospheric tower bottoms. In general,
refineries are classified as to the capacity of their atmospheric crude distillation unit in barrels per
day of crude input.
Vacuum distillation tower: This unit further distills atmospheric tower bottoms into vacuum gas oil
and vacuum tower bottoms. Vacuum gas oil is processed further in a Fluid Catalytic Cracking unit
(FCC) and the vacuum tower bottoms are either processed in a coking unit or asphalt unit or
blended to residual fuel oil.
Fluid catalytic cracking: The FCC unit cracks large molecule gas oils via catalytic cracking over
fluidized zeolite catalyst into light petroleum fractions, naphtha and distillates. The FCC naphtha is
sent to gasoline blending and the distillate is sent to distillate treating for blending into diesel fuel.
In many cases, the feed for the FCC unit is upgraded by catalytic hydrotreating or hydrocracking in
order to remove impurities and improve light product yields. One of the major products of FCC

REFINING AND GASOLINE SUPPLY
processing are light olefins which are light unsaturated hydrocarbons, these are processed further
in either an alkylation or a polymerization unit to produce high octane alkylate or cat poly gasoline.
Hydrocracking: A hydrocracking unit processes vacuum tower bottoms over a fixed bed of catalyst
in the presence of high pressure hydrogen and produces naphtha, jet fuel and distillate. Overall,
the process is relatively flexible in terms of ability to shift yields of product from naphtha, to jet fuel
to distillate. Product streams generally have low impurity levels but the overall process is one of
the more expensive processes, in terms of capital and operating costs.
Coking: This unit cracks the molecules of the heaviest petroleum fractions (vacuum tower
bottoms) into smaller molecules – light olefins, coker distillate and coker naphtha. As with the FCC
unit, the olefins are sent to the alkylation unit, the naphtha is sent to gasoline blending, and the
distillate is sent to diesel processing.
Asphalt Processing: This unit processes vacuum tower bottoms into asphalt cement. This heavy
tar material is mixed with aggregate (crushed rock) to produce the product known asphalt used in
road building and repair.
Distillate hydrotreating: Distillate hydrotreating of the raw distillate streams removes sulfur and
improves the diesel index of the resulting diesel fuel. This unit is required, in almost all cases, to
make ultralow sulfur diesel fuel.
Naphtha reforming: Heavy naphtha from the crude tower and other units is generally low in
octane. To improve and raise the octane number of this refining stream, a refinery typically treats
the heavy naphtha in a catalytic reformer. Reforming increases the octane. Prior to entering the
reformer, a naphtha hydrotreater is generally required to remove impurities (sulfur, olefins,
metals).
Alkylation: This unit reacts unsaturated C3, C4, C5 olefins with isobutane to produce high octane,
low RVP alkylate. The olefins are generally generated from the FCC and coking units. The
isobutane is sourced from the atmospheric crude tower and is produced in a C4 isomerization unit.
Alkylation units generally have two to three times the yield per unit of olefin feed compared to a
polymerization unit.
Isomerization: This unit can be used to convert normal paraffins into their isomers having higher
octane levels and lower RVP levels. Depending on whether the product is recycled through the unit
or not, the octane level of light straight run (LSR) naphtha can be increased from 70 RON (Research
Octane Number) to the low 80’s (no recycle) and 87‐93 range (with recycle). The blending RVP
value for LSR gasoline isomerized through a one‐pass process is 13.5 PSI.
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REF‐3

REFINING AND GASOLINE SUPPLY
Polymerization: This unit reacts unsaturated C3, C4, C5 olefins over a phosphoric acid catalyst and
produces a heavy, higher octane, low RVP naphtha stream (referred to as cat poly gasoline).
Depentanization: This unit may be a stand alone unit or part of individual processing units that
produce naphtha. In general, the purpose of the unit to separate C5 high RVP components from
naphtha streams in order to lower the naphtha stream’s Reid Vapor Pressure (RVP). The existence
of depentanization units in a refinery is generally not listed in published lists of refinery process
units. This unit is also referred to as C5/C6 removal.
Gasoline Blending: This process blends the various naphtha streams (FCC, coker, reformer,
alkylate, cat poly gasoline, and light straight run) plus other streams (butane, natural gasoline) to
produce finished grade gasolines. In gasoline blending, the process is optimized to blend the
correct volumes of component stocks in order to arrive at gasoline product that has the correct
final specification with respect to octane, Reid Vapor Pressure, sulfur, boiling range, and aromatics.
MAJOR REFINERIES SUPPLYING THE COLORADO/FRONT RANGE MARKETS
Overview of the Colorado Front Range Refinery Supply Network
As shown in Table REF‐1, there are six primary and four secondary refineries that can supply the
Colorado/Front Range market having a total capacity of 679 and 195.5 MBPD respectively.
Generally, the only refinery among the 10 plants that places most of its product in the Colorado
Front Range market is the Suncor Refinery in Commerce City. All of the other plants distribute a
significant fraction of their output to other markets and many have limits in how much of their
output can be placed in the Denver/Front Range market due to transportation constraints.
However, this network of refining does have some flexibility in replacing lost production in the
Colorado Front Range market due to refinery or pipeline upsets that do occur. It should be noted
that the Colorado market has a lower octane requirement then most of the surrounding markets
and some of the secondary supply refiners do not have storage capacity to segregate the lower
octane material as a separate product. They can ship higher octane material to Colorado but would
not want to give up octane value unless the combination of octane and market values supports
doing so.
As stated above, there are six primary supply refineries serving the Colorado/Front Range markets.
Five of these primary supply facilities are located out‐of‐state, with one, the Denver Suncor plant
located in Commerce City. All supply significant portions of their output to the Colorado/Front
Range areas. A short discussion on the capabilities and markets supplied by these plants are given
below.
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REF‐4

Suncor Commerce City Refinery
REFINING AND GASOLINE SUPPLY
The Suncor Commerce City Refinery is a 102 MBPD (DOE reported capacity) crude tower capacity
refinery that is the result of combining the original ConocoPhillips 62 MBPD refinery with the
Valero 27 MBPD refinery and expanding their combined capacity. These two refineries were able
to be consolidated into the present one refinery because of their close proximity to each other,
being located adjacent to each other in Commerce City.
Suncor initially acquired the ConocoPhillips refinery in 2003 and subsequently acquired the Valero
refinery in 2005. Since then, Suncor has invested in upgrading the plants by adding several new
processing units and integrating the two facilities. An important feature of this refinery is that it
has three separate crude towers – one small tower for processing heavy crude for asphalt
manufacture, the original Valero refinery crude unit designed to process very light crude (e.g. DJ
Basin) and a larger crude unit originally designed to process light – medium crude. Downstream
processing units consist of a vacuum tower, asphalt, FCC feed treating, FCC, reforming, diesel
hydrotreating, and two polymerization units. The Suncor refinery uses polymerization units for
production of cat poly gasoline via polymerization and does not have an alkylation unit. This means
that the Suncor refinery cannot produce gasoline with a low RVP (e.g. 7.0 RVP gasoline or Federal
reformulated gasoline) without substantial capital investments in the refinery which would include
the construction of a new alkylation unit.
Suncor is classified as a small refiner by the EPA with respect to meeting ULSD specs (2012) and
RFS2, but not for benzene. Suncor has to meet the new federal benzene specifications in 2011.
Being located in the Denver area, virtually all of Suncor’s refinery product is dedicated to the
Colorado market – Denver Front Range, Colorado Springs via Plains Kaneb pipeline, and Grand
Junction via rail. The Suncor refinery has pipeline connections to the NuStar Valero terminal,
ConocoPhillips terminal, Plains Kaneb pipeline to Colorado Springs, the Sinclair Henderson terminal,
and to the pipeline leading to Denver International Airport. Not surprisingly, Valero and
ConocoPhillips are exchange partners with Suncor, and trade product with Suncor, since they were
the original owners of the two refineries comprising the current Suncor plant.
The crude slate for the Suncor refinery consists of a variety of crudes ranging from light Denver‐
Julesburg (DJ) Basin crude, Wyoming sweet and sour, Wyoming asphaltic, Canadian synthetic and
Canadian medium and heavy crudes. Most of the crude processed at Suncor refinery (85 percent)
originates in the U.S. Rocky Mountain region. Suncor refining is a significant purchaser and
processor of DJ Basin and Green River Basin crude which is naturally high in RVP thus increasing
light ends which makes it more difficult to meet the new reduced RVP gasoline specifications. The
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REF‐5

REFINING AND GASOLINE SUPPLY
supply of light crudes similar to the DJ Basin crude is growing with development of the Niobrara
production area just north of Denver. This represents an opportunity for Suncor and, to some
extent, the Frontier Cheyenne refinery since such crude types are in abundance at Cushing and
have been discounted heavily to penetrate the market. These refineries will have lost opportunity
costs that are very real if they are limited in their use of these light crudes due to Low RVP gasoline
production requirements without making major refinery investments to accommodate these
growing crude streams.
Frontier Cheyenne Refinery
The Frontier Cheyenne refinery is a 52 MBPD crude tower capacity refinery and represents the
smallest of the Colorado primary supply refineries. Downstream processing units consist of
vacuum tower, coking, asphalt, FCC, reforming, diesel hydrotreating, and alkylation. The Frontier
Cheyenne refinery is the primary supply refinery for the Plains Kaneb product pipeline moving to
the Denver and Colorado Springs markets, with approximately 90 percent of its gasoline output
being supplied to the Colorado market. Historically, the crude slate for the Frontier Cheyenne
refinery consisted of heavy Canadian crude and a smaller amount of local light crudes, with
previous plant upgrades allowing the use of these crudes. With the decrease in light – heavy crude
price spreads plus light crude price discounting in the Rockies, the Cheyenne refinery has shifted its
crude slate to include proportionally more light crude.
Sinclair Rawlins Refinery
The Sinclair Rawlins refinery is a 74 MBPD crude tower capacity refinery and represents the next
smallest of the Colorado supply refineries. Downstream processing units consist of vacuum tower,
asphalt, coking, FCC feed treating, FCC, hydrocracking, reforming, diesel hydrotreating, and
alkylation. As originally considered with ownership of three refineries (Rawlins, Casper and Tulsa –
161 MBPD total capacity), Sinclair was not a small refiner, so the Rawlins refinery has to meet the
new federal benzene mandate in 2011. Product from the Sinclair refinery can access the Denver
market via its own Denver Products pipeline and accesses the Salt Lake City – Idaho markets via the
Pioneer product pipeline. Sinclair’s Henderson terminal is also supplied gasoline from the Magellan
Chase pipeline from El Dorado and from the Suncor Commerce City refinery. Historically, Sinclair
would ship 2 to 4 MBPD of gasoline from El Dorado KS to the Henderson terminal. CENEX is an
exchange partner of Sinclair’s at the Henderson terminal.
Similar to the Frontier Cheyenne refinery, the crude slate for the Sinclair refinery consisted of
heavy Canadian crude, heavy Wyoming crude, Canadian synthetic and local light crudes. With the
decrease in light – heavy crude price spreads plus crude price discounting in the Rockies, the
Sinclair refinery has shifted its crude slate to include more Rocky Mountain origin light crude and
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DENVER NFR FUEL SUPPLY COSTS AND IMPACTS 2011
REF‐6

acking out Canadian synthetic and Canadian heavy crudes.
REFINING AND GASOLINE SUPPLY
Starting in 2008 Sinclair, like a number of other smaller refiners, was facing a very tough margin
environment and increasing capital expense burden chose to consolidate a bit with the sale with
the sale of its Tulsa refinery and all of its company owned retail stations. Under these continued
lower margin environments, Sinclair’s ability to invest in upgrades for producing the newer
Denver/North Front Range specification gasolines may be limited. Construction of the new UNEV
product pipeline from Salt Lake City to Las Vegas would also provide Sinclair an additional,
alternative, market outlet for Sinclair should it not invest in Denver/North Front Range (DNFR)
specification gasoline. Its Henderson terminal could still obtain DNFR gasoline from Suncor, the
Midcontinent via Magellan Chase and from Frontier Cheyenne refinery to make up any product
shortfalls. This would tend to reduce the availability of product supply for the Denver/Front Range
market.
Frontier El Dorado Refinery
The Frontier El Dorado refinery is a 135 MBPD crude tower capacity refinery and represents one of
the larger Colorado primary supply refineries. Downstream processing units consist of vacuum
tower, FCC, reforming, diesel hydrotreating, alkylation and isomerization units. In addition, the The
Frontier El Dorado refinery is the primary supply refinery for the Magellan Chase product pipeline
moving to the Magellan Aurora and Sinclair Henderson terminals. The Frontier El Dorado refinery
has access to a wide variety of Midcontinent and Northern Tier markets via connections to
Magellan, NuStar Kaneb and Heartland pipeline systems. Besides making summertime 7.8 RVP
gasoline for Denver, the Frontier El Dorado also produces 7.0 RVP summertime gasoline for the
Kansas City market. The Frontier El Dorado refinery has access to numerous sources of crude from
the Midcontinent, West Texas, Gulf Coast, the Rockies and Canada. The Frontier El Dorado plant
does produce Colorado’s lower octane gasoline and is the primary if not only source of
Midcontinent gasoline accessing the Colorado market. If other refiners want to supply the
Colorado/front Range market they tend to exchange product with Frontier rather than produce and
segregate a lower octane/lower RVP gasoline product.
Frontier acquired the El Dorado refinery from Shell during Shell’s merger with Texaco. As part of
the 1999 deal, Shell had a 10‐15 year offtake agreement in which Shell acquired Frontier volumes
produced from this refinery. The agreement was structured so that contracted volumes declined
over time to the end of the agreement period, allowing Shell to find alternative supply sources for
its customers, while permitting Frontier to have a long term market for the products produced at
this plant. In the near term, with the agreement nearing an end, Suncor is about to succeed
Frontier El Dorado as the supply source for Shell Colorado Front Range retail stations. Shell has
completed a deal with Kroger to do a cross loyalty gasoline supply program where Kroger gasoline
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REF‐7

ewards are redeemable at participating Shell retail stations.
WRB ‐ ConocoPhillips Borger Refinery
REFINING AND GASOLINE SUPPLY
The ConocoPhillips‐Cenovus (WRB) Borger refinery is a 146 MBPD crude tower capacity refinery
and represents one of the largest and most sophisticated of the Colorado supply refineries.
Downstream processing units consist of vacuum tower, FCC feed hydrotreating, FCC, reforming,
diesel hydrotreating, and alkylation. One of the unique features of the COP Borger refinery is that
its NGL (natural gas liquids) processing capabilities are well integrated with large capacity
isomerization and alkylation processing units. This set‐up allows the Borger refinery to process
generally low priced raw NGL streams and produce high octane gasoline blending components. This
processing significantly enhances its gasoline yields and ability to make different specification
grades of gasoline.
The WRB Borger refinery has product pipeline access to numerous markets in the Midcontinent,
Northern Tier, West Texas‐New Mexico, Arizona and Colorado. Besides making summertime 7.8
RVP gasoline for Denver, the Frontier El Dorado also produces 7.0 RVP summertime gasoline for the
Kansas City market. The WRB Borger refinery processes primarily West Texas sour crude with
smaller amounts of WTI, Oklahoma crudes and Gulf Coast origin crudes. As part of the WRB joint
venture (ConocoPhillips and Cenovus), the Borger refinery was set up to process increasing
amounts of Canadian heavy crude with the addition of a coking unit. However, while the coking
unit has been constructed, the transition to processing increasing volumes of Canadian crude has
been limited by relatively low heavy‐light crude price spreads and a relatively stable if not growing
availability of southern origin and local crudes.
The WRB refinery ships product to the Colorado market via the ConocoPhillips product pipeline
from Borger to La Junta to Commerce City. NuStar owns one‐third of this product pipeline on an
undivided interest owner basis and is thus entitled to ship product from the Valero McKee facility
to Denver on this product pipeline.
Valero McKee Refinery
The Valero McKee refinery is a 171 MBPD crude tower capacity refinery and represents the largest
of the Colorado supply refineries. Downstream processing units consist of vacuum tower, asphalt,
FCC feed hydrotreating, FCC, reforming, diesel hydrotreating, and an alkylation. The Valero McKee
refinery has product pipeline access to markets in West Texas New Mexico, Arizona, Dallas and
Colorado. Besides making summertime 7.8 RVP gasoline for Denver, the Valero McKee refinery
also produces Arizona CBG gasoline for the Phoenix market and a small amount of reformulated
gasoline blend‐stock (RBOB) for the Dallas market. The Valero McKee refinery processes primarily
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REFINING AND GASOLINE SUPPLY
West Texas Intermediate crude with smaller amounts of WTS, Southeast Colorado, Southwest
Kansas and Gulf Coast origin crudes.
The Valero McKee refinery ships product to the Colorado market via the NuStar product pipeline
from McKee to Colorado Springs to Commerce City. As noted above, NuStar owns one‐third of the
ConocoPhillips ‐Denver product pipeline on an undivided interest owner basis and is thus entitled
to ship product from the Valero McKee facility to Denver on the COP product pipeline as well.
Operations Summary
A summary of year 2009 operations of the six primary supply refineries for the Colorado market is
presented in Table REF‐2. The Suncor and WRB Borger refineries are shown to have operated their
crude towers at or above 92 percent range in 2009 – which is generally considered to be close to
full capacity. In opposition to this, the two Wyoming refineries, Sinclair and Frontier, are shown to
have operated in the 73 to 78 percent range – symptomatic of the decline in product demand in
Wyoming, especially of diesel fuel.
Two refineries are most dependent on the Colorado/Front Range area markets for placing their
product, Suncor and Frontier Cheyenne. The Suncor refinery places virtually all‐of‐its gasoline
product in the Colorado market. The Frontier Cheyenne refinery places about 90 percent of its
gasoline in the Colorado market.
The other principle refineries supplying the Front Range / Colorado market produce product for
multiple markets. Both of the Texas‐based refineries, ConocoPhillips Borger and Valero McKee,
place about 18 – 19 percent of their gasoline production in the Colorado market. In Wyoming, the
Sinclair Rawlins refinery places the smallest volume of gasoline into the Colorado market. This is
somewhat dependent on the amount of gasoline this refinery can produce. Its yield of gasoline as
a percentage of crude run is less than average at 35.5 percent. Sinclair places about 42 percent of
its gasoline in the Colorado market. Lastly, the Kansas‐based refinery, Frontier El Dorado, places
about a third of its gasoline into the Colorado market.
The supply of 7.8 psi RVP gasoline produced for the Colorado market is easily large enough to
supply both the required low gasoline volatility Denver‐North Front Range Ozone SIP area markets
and the surrounding attainment areas, as well as additional outlying areas, such as the southern
Colorado Springs‐Pueblo region. This indicates that the Denver/North Front Range market, with
estimated 7.8 psi gasoline demand at 78 MBPD, is oversupplied with summertime 7.8 psi RVP
gasoline. This can be due to tankage limitations at either the upstream refineries or in the
destination market terminals but is probably mostly due to tankage limitations at the Denver area
terminals. The refining and pipeline companies in beginning to supply the market with 7.8 psi
gasoline in the summer avoided the capital cost of building additional tankage required to store
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DENVER NFR FUEL SUPPLY COSTS AND IMPACTS 2011
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REFINING AND GASOLINE SUPPLY
both 7.8 and 9.0 psi gasoline. The overall result is that 7.8 RVP gasoline is distributed to retail sites
outside of the designated ozone non‐attainment market area, displacing the higher volatility 9.0 psi
RVP gasoline. Estimates of the summer supply of 7.8 psi gasoline are given in Table REF‐2.
Survey results indicate that ethanol supply for the product terminals in the core Commerce City –
Aurora – Henderson terminals is sourced from numerous locations. In general, refiner marketers
seek to source the lowest laid in cost of ethanol supply. Most survey respondents indicated that
they sourced ethanol from production plants in Colorado, Wyoming, Kansas, Nebraska and Iowa.
One important factor in sourcing the ethanol is transportation mode available – rail or truck.
Larger ethanol plants in the Nebraska, Iowa, and Illinois corridor have rail loading facilities while
smaller plants closer to the Front Range may only provide truck transport. With respect to the
refined product terminals themselves, only the Ethanol Management facility and the Suncor
refinery have rail unloading facilities and can also load trucks for delivery to the other terminals.
The other product terminals are believed to have only truck receipt facilities for ethanol.
One of the primary objectives of this study is to determine the cost and supply impacts of
implementing a low volatility gasoline program. A principle finding of this study is that each of the
options under consideration has its own cost and fuel supply impacts, that the more stringent the
fuel control scenario, the higher the cost. These cost components include; refinery capital costs,
cost of refinery operation, lost product value due to rejecting higher value streams to lower value
end uses, increasing supply costs due to companies shifting their product out of the Front Range
market to avoid investment. Gasoline supplies were also more impacted under the more severe
fuel options. Offsetting costs and supply impacts, the most stringent gasoline specification
scenarios are expected to achieve the largest air quality benefit. In increasing severity, the four
scenarios analyzed were:
1) 7.8 RVP gasoline with no federal one pound ethanol waiver
2) 7.0 RVP gasoline with the federal one pound ethanol waiver
3) 7.0 RVP gasoline with no federal one pound ethanol waiver
4) Reformulated Gasoline (RFG)
REFINERY SUPPLY COST IMPACT
In conducting this study, EAI, Inc. modeled the refinery operations of the six primary supply
refineries for the Denver/North Front Range market in order to evaluate the supply and cost
impacts of the proposed fuel specification changes. In general, the objective was to produce
similar volumes of the proposed specification fuels and, failing that, to see what levels could be
produced. An overview of the aggregate modeling results are shown in Figure REF‐2 which shows
the current base level of gasoline blending streams being considered for the total Colorado Front
Range gasoline pool and the Colorado Front Range blend stream.
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REFINING AND GASOLINE SUPPLY
Figure REF‐2
Aggregate Refinery Representing Primary Plants Supplying Colorado
Gasoline Blend Streams from Model of Each Plant
Process Configuration represents Suncor, Valero‐McKee, WRB‐Borger, Frontier‐Cheyenne, Frontier‐El Dorado and Sinclair‐Rawlins. Total
gasoline production is approximately 341 MBPD. Front Range supply is approximately 121 MBPD and the supply necessary for the ozone
non‐attainment area (2009 basis) is 78 MBPD not including the potential spillover areas.
ACOD_O 674.7
CRUDE 602.2
CHARGE
Atmospheric Crude Tower
VCOD 286.7
Vacuum Crude Unit
Asphalt
Blowing
ASPH 24.4
Amine Treater
Sulfur Recovery
(Claus Unit)
Gasoline Blend Streams
Total CO FRNGE
Gas Processing Merox Treaters
SLFR 918.7
Butane
7.7 3.2
LSR 20.9 9.7
Light Naphtha
Hydrotreater
Isomerization
Isomerate 57.5 13.6
ISMR 63.1
Reformate
Hvy Naphtha
Hydrotreater
Benzene Extraction Reformer
103.3 39.7
RFMR_FD 140.7 RFRM 147.5 T T L GASO PRD
FRONT OZONE
Merox
Treater
Jet/Kerosene
Oxygenate
5.3
Oxygenate
1.3
RANGE NATNM
331.8 120.7
Distllate
OXGN 4.9 GASO DEMAND
Distillate
Hydrotreater
Hydrocracker Gasoline
FRONT OZONE
RANGE NATNM
122.8 78
DST_HYD 191.8
Hydrocracker
5.0 1.6
Solvent
Deasphalting
CKER 75.0
Gas Precessing/
Buty/Propylene
Extraction
FCC Feed
Hydrotreater
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DENVER NFR FUEL SUPPLY COSTS AND IMPACTS 2011
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CHCR 15.5
Alkylation Unit
ALKY 49
Fluid Catalytic
Cracker
Alkylate
FCC Gasoline
Natural Gas
Purchases for H2
HYDR 172.0
29.5 9.3
102.6 42.3
FCC_FEE 120.2 FCCR 209.3
Gas Processing/H2
to Hydroreating
Methane Reforming
H2 Production
Delayed or
Fluid Coker
GasolineTreating and Blending
Copyright ©: EAI, Inc., 2011
HIGHER RVP OPTIONS: 7.0 PSI RVP CONVENTIONAL GASOLINE WITH WAIVER AND 7.8 PSI RVP
CBOB WITH NO WAIVER
The gasoline blends that that have the least impact on fuel production costs and supply tightness
are the two highest RVP gasolines examined. Both the 7.0 psi RVP CBOB (with one psi waiver) and
the 7.8 psi RVP gasoline (with no one psi waiver), were found to require the least investment and
refinery modification and provided the least volume availability decline. This study found that all of
the refiners would be able to produce some level of these fuels. This would result in a relatively
small impact in terms of overall supply availability.
The required investments for all refiners fall generally in the arena of depentanization, i.e. removal
of C5 higher boiling components. One physical property of pentanes or C5’s is that they have an
inherently high RVP. Pentanes are a normally occurring component of crude oil (to varying degrees
dependent on crude type and source) and also are produced as part of refinery operations. Unless
removed or selectively avoided in crude selection, pentanes are significant contributors to the RVP
level of gasoline blends. Different refiners would require this component separation but without
details of the in plant units, it is hard to discern the exact required investment level.
The ConocoPhillips Borger refinery is estimated to require the least amount of C5 removal
investment due to the overall sophistication of its plant and its current process configuration of
processing significant amounts of natural gas liquids requiring separation. Similarly, the Valero
McKee refinery and the Frontier El Dorado refinery are estimated to require some but not

significant investments to expand C5 removal.
REFINING AND GASOLINE SUPPLY
The three remaining refineries, Suncor, Sinclair, and Frontier – Cheyenne, are estimated to require
significant investments in C5 removal due to their small size and estimated lack of C5 removal
equipment. Each refinery presently has limited capability to remove C5 pentanes from the various
refinery streams. Frontier’s estimated fuels investments may decrease with its recent investments
to meet various EPA requirements related to a 2009 ruling.
The Suncor refinery represents a special case for two reasons. First, the Suncor plant is a
combination of what was previously two separate, smaller refineries both of which did not have
any significant C5 removal facilities. Because this plant is a combination of two older refineries,
there is a physical separation of plant facilities. There is also limited expansion space available for
the combined plant. Because of the inherent inefficiencies of the two combined plants and limited
space for expansion; proximity to highways, a creek and rail line, the Suncor refinery experiences
higher required investment costs. Second, the crude tower of the original Valero Commerce City
refinery is limited in its ability to handle different crude slates. It was designed to process very light
DJ Basin crude which continues to be a major portion of the Suncor refinery crude slate. DJ Basin
crude is a heavy condensate mostly produced from predominately gas wells in the DJ Basin; it
contains 4 to 10 percent C5 liquids. As a result, Suncor refinery has to both install new equipment
and size it for a larger than normal amount of C5 liquids.
The Suncor refinery is the primary supply source for Denver NFR non‐attainment area gasoline. It
produces gasoline for not only for its own retailing needs, but also supplies significant shares of its
gasoline volumes to other refiner marketers.
In all cases for all refiners, significant volumes of C5 liquids would have to be removed from the
summer specification gasolines, it is important to consider the outlets and economic impacts of this
removal. Market outlets include (1) blending into 9.0 psi conventional gasoline for distribution to
the areas outside of the non‐attainment area, (2) movement via rail or NGL pipeline to a major
natural gas liquids processing center, e.g. Conway, KS, and (3) movement via rail to Edmonton for
blending into Canadian heavy bitumen to produce pipeline specification heavy crude.
Ability to blend into 9.0 summer gasoline is very limited due to this grade of gasoline already being
blended to close to RVP specification. Comparison of year 2009 Edmonton spot condensate prices
with Conway natural gasoline prices net of transportation indicate that movement to Conway
entails the smaller loss relative to selling the pentanes at Denver gasoline value.
LOW RVP OPTIONS: 7 PSI CBOB NO WAIVER AND REFORMULATED GASOLINE
In general, the low RVP conventional fuels (7.0 psi RVP conventional gasoline blendstock (CBOB)
with no one psi waiver, and reformulated gasoline), require more substantial investments for the
smaller refineries that heretofore have had to make minimal investments, i.e. have small refiner
exemptions. Similar to the previous case, the larger refineries, ConocoPhillips Borger, Valero
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REFINING AND GASOLINE SUPPLY
McKee, and Frontier El Dorado, would have to make minimal investments in order to produce the
two more stringent products. Valero McKee already produces RFG for the Dallas market and
Arizona Cleaner Burning Gasoline (CBG) for the Phoenix market. ConocoPhillips refinery appears to
have the sophistication to make these products already. Frontier El Dorado refinery would need
some investment.
Suncor refinery would need significant investment in that the refinery would be significantly short
of high octane, low RVP blendstock. This is mostly due to the low yield of this product from the
plant’s olefin polymerization units compared to the alkylation units existing at the other primary
supply refineries. Historically, some alkylate has been brought in via rail to the original
ConocoPhillips Commerce City refinery in the summer to help with meeting gasoline blend
specifications. Meeting the product specifications of the low RVP/RFG fuels without significant
deterioration in gasoline yields would mean significant refinery investment which would include
the construction of a new alkylation unit at the Suncor refinery.
The three major outlying refineries, COP Borger, Frontier El Dorado and Valero McKee, are
estimated to need relatively small capital investments in excess of that required for C5/C6 removal
for these two fuels. Frontier Cheyenne and Sinclair Rawlins would need capital investments. From
comments of Sinclair relative to investments for these more stringent specification fuels (7.0 RVP
CBOB with no waiver and RFG) indicate that Sinclair may opt to not invest in fuels for the non‐
attainment areas. Sinclair also places the smallest amount, but highest percent of its total
production, into the Denver market. Sinclair may seek to replace its current NAA volume with
supply from the other suppliers and move product to other markets.
IMPACT SUMMARY
A summary of the incremental manufacturing costs for the four proposed gasoline specifications is
presented in Table REF‐3. These results include three cost component categories; incremental
operating costs, allocated capital costs and lost light end value.
The lowest cost and least supply impact fuel options are (1) the 7.0 pound maximum RVP with one
pound ethanol waiver, and (2) the 7.8 pound maximum RVP with no ethanol waiver, options. Both
would be lower in cost and have the least supply impacts compared to the more severe options of
going to 7.0 pound maximum RVP with no ethanol waiver, or federal RFG. In general, the lowest
cost category is incremental operating costs followed by allocated capital costs and then C5/C6 lost
value. All four options entail significant C5/C6 rejection which prospectively result in higher costs
for summertime gasoline.
Some of the key observations are presented below:
Total average weighted incremental production costs range from 11 to 19 CPG with the
summer RFG case being the highest and the 7.0 psi with waiver and the 7.8 psi with no
waiver the lowest at 11.4 and 12.3 CPG respectively.
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REFINING AND GASOLINE SUPPLY
The range of costs for the most realistic representation of refinery response was as follows:
o 7 psi with Waiver: The costs representing the majority of the non‐attainment area
gasoline volume was in the range of 9 to 13 CPG. This includes a high of 2 CPG for
incremental operating costs, 8 to 14 CPG for light‐end rejection and capital costs
ranging from 0.7 to 2.2 CPG of output (based on amortizing capital costs over 20
years).
o 7.8 psi with No Waiver: At 12.3 CPG total weighted manufacturing cost, this fuel
scenario was very close to the 7 psi case with waiver since the required gasoline psi
level is fairly close. Most of the additional cost for the 7.8 case was for additional
light ends rejection.
o 7 psi – No Waiver: The costs representing the majority of the non‐attainment area
gasoline volume was in the range of 2 to 24 CPG. This includes a high of 2.8 CPG for
incremental operating costs, 1 to 18 CPG for light‐end rejection and capital costs
ranging from 1 to 4.4 CPG of output (based on amortizing capital costs over 20
years). It should be noted that the total capital costs for this case were relatively
high but the investment increased the usage of light ends thus lowering the light
end rejection penalty.
o RFG Case: This was the highest cost case in terms of capital expenditures, light end
rejections and incremental operating costs with a range of 13 to 26 CPG for the
largest volume suppliers. Some of the refiners having much smaller presence in the
non‐attainment area had costs in the 1 to 1.5 CPG range.
The high end of the range for production costs generally reflected the Suncor and Frontier
Cheyenne plants due to their large presence in the non‐attainment market area, plant modification
requirements and light end rejection requirements. The output of these plants is required to
satisfy the market and would be difficult to replace with other sources. For this reason, their
incremental production costs are likely to set the market clearing price for more severe attainment
fuels (7.0 psi with no waiver and RFG gasoline) which are likely to be less abundant for this market
than current gasoline grades.
In Figure REF‐3, a summary of capital, operating and light‐end rejection costs are presented for the
primary refineries supplying the Colorado Front Range. EAI, Inc. modeled each plant in addition to
reviewing information supplied by some of the refiners. The costs presented in the figure
represented a volume weighted summary based on expected supply of attainment gasoline from
each plant. In summary four fuel options were analyzed;
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DENVER NFR FUEL SUPPLY COSTS AND IMPACTS 2011
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Cost, CPG
REFINING AND GASOLINE SUPPLY
Figure REF‐3
Manufacturing Cost Increases Due To Fuels Specification
Changes: Production Weighted Cost Composite for Primary
Refineries Supplying Denver‐Front Range
20.00
18.00
16.00
14.00
12.00
10.00
8.00
6.00
4.00
2.00
0.00
Capital Costs Operating Costs C5/C6 Reject
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DENVER NFR FUEL SUPPLY COSTS AND IMPACTS 2011
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Copyright ©: EAI, Inc., 2011
Estimates of capital investments required are provided in the table below for the refineries and
cases. Excepting Frontier Cheyenne and Suncor Commerce City refineries, capital costs are
associated with upgrades to the existing plant facilities to remove C5/C6. As noted above, Valero
McKee currently makes a certain level of RFG, COP Borger and Frontier El Dorado make 7.0 low RVP
for the Kansas City market. Therefore it was assumed that minimal investments would be required
for the more stringent fuels. Both Frontier Cheyenne and Suncor Commerce City refineries would
require substantially higher investments to comply with any of the considered fuel options due to
needed infrastructure. Estimated total industry capital investments range from $250 million for the
higher RVP options (7.0 pound maximum RVP with one pound ethanol waiver, and 7.8 pound
maximum RVP with no ethanol waiver), to $560 million for the lower maximum RVP options (7.0
pound maximum RVP with no ethanol waiver) and $710 million for federal RFG.

REFINING AND GASOLINE SUPPLY
GASOLINE UPGRADE ESTIMATED CAPITAL INVESTMENTS
Units: Million $
7.8 No
Waiver
7.0
W/Waiver
7.0 No
Waiver
RFG
Suncor Commerce City 110 110 350 400
Frontier Cheyenne 50 50 120 220
Valero McKee 25 25 25 25
Frontier El Dorado 20 20 20 20
COP Borger 10 10 10 10
Sinclair Rawlins 35 35 35 35
TOTAL 250 250 560 710
* Estimates exclude benzene removal capital
An overview of the light end rejection required to meet the Front Range gasoline supply RVP
specifications for the non‐attainment area plus the volume supplied to the immediate market is
shown in Figure REF‐4. This volume in the higher RVP cases (7.8 CBOB no waiver and 7.0 with
waiver) amounts to 8 to 9 MBPD of the available gasoline pool or 15 to 16 percent of the total
available pool. Preparation of the current 7.8 psi with waiver gasoline requires that about 2.2
MBPD of light ends be taken out.
Figure REF‐4
Front Range Light End Rejection to Meet RVP & 1 lb Waiver Options
The light end rejection requirements to meet the most stringent RVP option would be on the order of 13 MBPD representing 14 percent
of the overall non‐attainment pool including spill over volume. This would have to be replaced with other streams that have lower
RVP levels but also can help the overall gasoline pool meet other specifications such as octane level, drivability index, T50, etc.
Rejected Gasoline, MBPD
14.00
12.00
10.00
8.00
6.00
4.00
2.00
0.00
No Butanes 7.8_w_wvr 7.8_wo_wvr 7.0_w_wvr 7.0_wo_wvr
Lost LSR/Isomerate For NATNM Gasoline Lost LSR/Isomerate For NATNM Plus Spillover Gasoline
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DENVER NFR FUEL SUPPLY COSTS AND IMPACTS 2011
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25.0%
20.0%
15.0%
10.0%
5.0%
0.0%
Copyright ©: EAI, Inc., 2011

REFINING AND GASOLINE SUPPLY
This light end rejection is composed of increasing amounts of C5/C6 material contained in what
here to fore has been the refinery light straight run and isomerate streams, see Figure REF‐5. The
lower RVP cases (7.0 CBOB no waiver and RFG) entail removal of 12 – 13 MBPD of light ends – light
straight run gasoline, i.e. require significantly higher volumes of material to be rejected from the
gasoline pool to a lower value natural gas liquids value pool.
Figure REF‐5
Front Range Gasoline Pool Blending to Meet RVP & 1 lb Waiver Options
Preliminary results of the “whole pool” blending model indicate that all light straight run gasoline would have to
be removed to meet the 7.8 RVP without the waiver and 18 percent of the isomerate. For the 7.0 RVP with no
waiver, at least 60 percent of the isomerate would have to be removed. This modeling was done using the
aggregate gasoline pool components from the six refineries supplying the Colorado Front Range. Lost LSR and
isomerate where replaced with alkylate to maintain overall gasoline volume levels. This would tend to overshoot
gasoline pool octane levels.
RVP, PSI
9.00
8.00
7.00
6.00
5.00
4.00
3.00
2.00
1.00
0.00
No Butanes 7.8_w_wvr 7.8_wo_wvr 7.0_w_wvr 7.0_wo_wvr
Butane Purchase LSR Isomerate Alkylate Oxygenate
Poly Gasoline Reformate FCC Gasoline Hydrocrack Gaso Ethanol
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DENVER NFR FUEL SUPPLY COSTS AND IMPACTS 2011
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Copyright ©: EAI, Inc., 2011
In addition to light end rejection to meet the lower RVP gasoline requirements, there is also
potential for current suppliers to shift their gasoline volume from the non‐attainment market to
other markets to avoid or minimize their need to produce attainment fuels for the Denver/Front
Range market. Based on a review of each plant and likely responses, EAI, Inc. estimates that there
is a strong likelihood that at least 10 to 15 MBPD of production from existing plants for the
Denver/Front Range market will be lost due to rejection of light ends and shifting product to
alternative ozone attainment markets If the market were to remain tight with respect to non‐
attainment fuels, there is some a good possibility that refiners will attempt to increase their
production of these fuels due to higher margin realization. As summarized in Figure REF‐6, the
total potential volume varied depending on the case considered from a high of 37 MBPD to
approximately 24 MBPD of shifted and rejected gasoline and light ends respectively. Rejection or
shifting of streams is offset, to some extent, by capital expenditures. For example, increasing the
production of alkylate by a refiner would provide the refiner with a higher octane and lower RVP
blend stock that might also enable the usage of additional light ends that were going to be rejected.
Installation/expansion of an isomerization unit might allow a refiner to use additional straight run

naphtha that might otherwise be rejected.
REFINING AND GASOLINE SUPPLY
Figure REF‐6
Potential Gasoline Volume Loss and Shift
Denver Front Range Market
Light end rejection will be made up in part by increased crude runs, ethanol and increased production of
other gasoline blend components such as isomerate and alkylate. However, there is a good possibility
that 10 to 15 MBPD of gasoline supply will be lost especially during the early stages of the program.
RFG_WNTR
RFG_SMR
CBOB_7.8PSI_NO_WVR
CBOB_7PSI_WITH_WVR
CBOB_7PSI_NO_WVR
0 10000 20000 30000 40000
EAI, INC. (ENERGY ANALYSTS INTERNATIONAL) EAI, INC.
DENVER NFR FUEL SUPPLY COSTS AND IMPACTS 2011
REF‐18
Volume, BPD
REJECT C5/C6 SHIFTED VOLUME
Copyright ©: EAI, Inc., 2011
The cost to the refiner of removing C5/C6 from gasoline for all four fuel options considered is large.
In all instances, the C5/C6 normally sold as summer grade gasoline has to be sold as natural
gasoline in the nearest large volume, pipeline accessible market, in this case Conway, KS. This
results in a significant opportunity loss to the refiner. To place this in context, the historical spread
of Denver unleaded regular gasoline versus Conway natural gasoline netted back to Denver was
examined. This spread is shown graphically in Figure REF‐7.
As shown in Figure REF‐7, gasoline values are seasonally high in the summer while natural gasoline
prices (C5/C6) are seasonally low in summer, generally the loss of rejecting C5/C6 from gasoline to
the natural gas liquids market is maximized in the summer. As more metropolitan areas move
lower RVP gasolines, this price spread should become greater as more C5/C6 material is rejected
from summertime gasoline. Additionally, new drilling and production technology is being applied
to new areas, e.g. Niobrara Basin northeast of Denver, Eagle Ford and Granite Wash of Texas, that
will produce significant new volumes of natural gas condensate streams and further add to C5/C6
supply. At some point, there should be sufficient incentive to convert C5/C6 to lower RVP gasoline

REFINING AND GASOLINE SUPPLY
blendstocks. Lastly, there is a high probability that refiners will seek to minimize C5/C6 rejection
volumes by crude selectivity, e.g. running more Canadian synthetic with lower light straight run
naphtha content versus the lighter, high condensate crudes like DJ Basin.
C5/C6 Loss , cpg
Figure REF‐7
Loss Of Value Selling Denver Gasoline at Conway
Natural Gasoline Price
Calculated as – (Conway price minus Denver gasoline price minus pipeline transport)
Loss maximizes in summer when most C5/C6 rejected.
150
140
130
120
110
100
90
80
70
60
50
40
30
20
10
0
C5/C6 Loss
JAN_06
APR_06
JUL_06
OCT_06
JAN_07
APR_07
JUL_07
OCT_07
JAN_08
APR_08
JUL_08
OCT_08
JAN_09
APR_09
JUL_09
OCT_09
JAN_10
APR_10
JUL_10
OCT_10
EAI, INC. (ENERGY ANALYSTS INTERNATIONAL) EAI, INC.
DENVER NFR FUEL SUPPLY COSTS AND IMPACTS 2011
REF‐19
Copyright ©: EAI, Inc., 2011

REF‐20
REFINERY CONFIGURATION PROFILES, 2011 BPD
REFINERIES HAVING ACCESS TO THE COLORADO FRONT RANGE MARKET
REFINERY UNIT
REF UNIT
CATEGORY
UNIT
DESCRIPTION
Table REF‐1
‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐PRIMARY REFINING SUPPLY‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐SECONDARY REFINING SUPPLY‐‐‐‐‐‐‐‐‐‐‐‐ ‐‐‐‐‐‐‐‐‐‐REFINING TOTALS‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐
SUNCOR
CMRC CITY
FRONTIER
CHEYENNE
SINCLAIR
RAWLINS
FRONTIER
EL DORADO
WRB
BORGER
VALERO
MCKEE
SINCLAIR
CASPER
COP
BILLINGS
EXXONMOBIL
BILLINGS
CENEX
LAUREL, MT
TOTAL
PRIMARY
TOTAL
SECONDARY
CRD_ATM_TWR DSTLTN ACOD_OPC 102000 52000 74000 135000 146000 170000 22500 58000 60000 55000 679000 195500 874500
CRD_VCM_TWR DSTLTN VCOD 33500 26000 35700 53200 75000 53200 6000 35000 27500 31300 276600 99800 376400
CAT_RFM_CYCLIC RFRM CYLC 0 0 0 0 0 0 0 0 0 0 0 0 0
CAT_RFM_CONTSREGEN RFRM RGNR 0 0 0 0 0 28900 0 0 0 0 28900 0 28900
CAT_RFM_SEMIREGEN RFRM SMGR 20000 9000 12600 27450 29000 18500 5500 12200 12000 12500 116550 42200 158750
FCC_FRESH_FEED FCCR FLUID 27000 12000 20600 36000 55000 54465 10000 19400 18000 14000 205065 61400 266465
THRM_CRCK_DLYD CKER DLY_CKNG 0 14000 16000 16650 0 0 0 20000 0 0 46650 20000 66650
THRM_CRCK_FLUID_COKE CKER FLD_CKNG 0 0 0 0 0 0 0 0 10000 0 0 10000 10000
THRM_CRCK_OTH CKER OTHR 0 0 0 0 26000 0 0 0 0 15000 26000 15000 41000
ASPHLT ASPH ASPH 10500 0 7000 0 0 0 0 0 14500 19000 17500 33500 51000
ISOM_C4_FEED ISMR BTNE 900 1200 0 0 14000 0 0 3600 0 2500 16100 6100 22200
ISOM_C5_6_FEED ISMR PNT_HXN 0 0 0 11250 30000 7000 0 0 0 0 48250 0 48250
ALKY_HYDRFLRC_ACID ALKY HYDR_ACID 0 4000 0 12150 17000 0 0 6800 0 4300 33150 11100 44250
ALKY_SULF_ACID ALKY SLF_ACID 0 0 3900 0 0 9500 0 0 5000 0 13400 5000 18400
POLYZATION POLY POLY 3500 0 300 0 0 0 1000 0 0 0 3800 1000 4800
OXY_MTBE OXGN MTBE 0 0 0 0 0 2200 0 0 0 0 2200 0 2200
OXY_TAME OXGN TAME 0 0 0 0 0 2700 0 0 0 0 2700 0 2700
HYDRO_CRACK_DST_UPGRD CHCR DST_UPGR 0 0 0 0 0 0 0 0 5500 0 0 5500 5500
HYDRO_CRACK_RISID_UPGRD CHCR RSD_UPGR 0 0 0 0 0 29500 0 0 0 0 29500 0 29500
HYDRT_PRETRT_CAT_CRKR_FEED CHTR FCC_FEED 25200 0 17400 40500 73000 0 0 23000 0 15700 156100 38700 194800
HYDRT_PH_FCC_NPTH CHTR FCC_NPTH_FEED 0 11000 0 0 0 3400 0 0 0 0 14400 0 14400
HYDRT_KERO_JET_DESUL CHTR KERO_JET 10800 0 13000 9000 8160 0 0 4224 13344 0 40960 17568 58528
HYDRT_OTH_NPTH_DESUL CHTR NPH_DSLF 0 0 0 16200 0 22000 0 0 32000 0 38200 32000 70200
HYDRT_OTH CHTR OTHER 0 0 0 0 0 0 0 0 7500 0 0 7500 7500
HYDRT_OTH_DST CHTR OTH_DSTL 0 0 0 0 13000 0 0 49000 6000 0 13000 55000 68000
HYDRT_PRETRT_CAT_RFRM_FEED CHTR RFMR_FD 18500 10000 13500 21600 40000 39844 7500 0 0 15100 143444 22600 166044
HYDRT_DSL_DESUL CHTR SRUN_DSTL 18900 18000 13900 46800 28000 32368 8500 0 9000 20800 157968 38300 196268
HYD_MMCFD_RCVRY_MEMBRN HYDR MBRN 0 0 0 0 0 0 0 12099 4995 0 0 17094 17094
HYD_MMCFD_PROD_STM_MTHN_REFRM HYDR MTH_RFRM 0 6105 52000 45510 99900 0 0 34410 24420 23310 203515 82140 285655
HYD_MMCFD_RCVRY_OTH HYDR OTHR 28860 0 0 0 0 0 0 0 0 0 28860 0 28860
HYD_MMCFD_RCVRY_PRSR_SWNG_AB HYDR PSAB 0 0 0 22200 11100 0 0 51393 0 23310 33300 74703 108003
COKE COKE COKE 0 800 6100 1000 1250 0 0 1020 490 0 9150 1510 10660
SULFUR SLFR SULFUR 94 105 180 260 400 60 20 224 0 90 1099 334 1433
AROM_BTX ARMT BTX 0 0 0 1980 0 0 0 0 0 0 1980 0 1980
Based on O&J or EIA Information (Latest Available 2011 and early 2010 respetively)
Units shown in color are units that can help make Lower RVP and/or higher octane streams to replace lost light ends
EAI, INC. (ENERGY ANALYSTS INTERNATIONAL) EAI, INC.
DENVER NFR FUEL SUPPLY COSTS ‐ IMPACTS 2011
TOTAL
REFINING

REF‐21
Table REF‐2
REFINING COMPANY OPERATIONS SUMMARY 2009
Units: BPD
Refinery Suncor ConocoPhillips Valero Frontier Sinclair Frontier Summary
Location Commerce City CO Borger TX McKee TX Cheyenne WY Rawlins WY El Dorado KS Totals
Crude Tower Capacity 104000 145000 171000 52000 74000 135000 681000
Crude Tower Input 95300 136800 151600 41000 53800 121000 74000
Percent Utilization 91.6 94.3 88.7 78.8 72.7 89.6 10.9
Unsed Capacity 8700 8200 19400 11000 12200 14000 73500
Colorado Pipeline Supplied Local ConocoPhillips NuStar, ConocoPhillps Plains Wyco Denver Products Magellan Chase
Gasoline Production 47200 98589 81706 17178 23638 64556 332867
Colorado Gasoline Supplied 47200 17800 15050 15330 9909 21800 127089
Estimated 7.8 Summer Gasoline 37000 8000 23000 10500 6000 21800 106300
Percent Gasoline to Colorado 100.0% 18.1% 18.4% 89.2% 41.9% 33.8% 38.2%
Alternative Markets * Colorado Springs Amarillo Amarillo Cheyenne Rawlins Wichita
Grand Junction Lubbock Lubbock North Platte Salt Lake City Kansas City
Albuquerque Albuquerque Colorado Spring Pocatello Midcontinent
El Paso El Paso Boise Northern Tier
Tucson Tucson Spokane
Phoenix Phoenix
Kansas City Dallas
Northern Tier Colorado Springs
* Direct access via pipeline, Grand Junction via rail
Midcontinent ‐ KS, MO, OK
Northern Tier ‐ IA, NE, ND, SD, MN
EAI, INC. (ENERGY ANALYSTS INTERNATIONAL) EAI, INC.
DENVER NFR FUEL SUPPLY COSTS ‐ IMPACTS 2011

REF‐22
OZONE FUEL SCENARIO IMPACT MATRIX
COLORADO OZONE ATTAINMENT STRATEGY SUPPORT
Table REF‐3
OZONE FUEL STRATEGY CBOB CBOB CBOB RFG
COST COMPONENTS CBOB/7 PSI WITH WVR 7.8 PSI / NO WVR 7PSI / NO WVR SUMMER
Time to Implement (Max(W Contingency)) Months 60 60 60 60
(For all mjr splrs to accommodate)
Incremental Operating Costs (CPG)
Weighted Average 0.25 0.25 1.48 1.90
Highest 2.00 2.00 2.80 4.00
Lowest 0.04 0.00 0.05 0.05
(Average Industry Per NATN BBL)
Capital Costs (MM $) (1)
Total Industry $250 $250 $560 $710
Per Daily NATN BBL $3,131 $3,160 $7,014 $9,696
Highest $110 $110 $350 $400
Lowest $10 $10 $10 $10
Allocated Capital Costs (20 Year, CPG) 2.02 2.04 3.81 5.09
Supply Reduction & Shift (MBPD)
Light End Rejection 11.4 12.7 13.1 13.0
Gasoline Mrkt Shift 12.1 12.1 15.9 24.9
Supply Reduction (Percent of NATN Market)
Light End Rejection 14.3% 16.0% 16.4% 17.7%
Gasoline Mrkt Shift 15.1% 15.3% 19.9% 34.0%
Lost Light End Value (CPG of ATNM Supply) (2) 9.1 10.0 10.9 11.8
Highest Cost 9.4 10.3 17.4 17.4
Lowest Cost 8.2 9.0 0.9 3.6
Total Estimated Costs (CPG) (3) 11.4 12.3 16.2 18.8
(1) Based on Survey plus EAI, Inc. estimates not all refiners provided estimates; total capital likely to be under actual required
(2) Based on light end losses being all pentane plus material; if butane would increase costs
(3) Capital, Operating and Lost Light End Total Cost
EAI, INC. (ENERGY ANALYSTS INTERNATIONAL) EAI, INC.
DENVER NFR FUEL SUPPLY COSTS ‐ IMPACTS 2011

DST
DISTRIBUTION SYSTEM IMPACTS
EAI, INC. (ENERGY ANALYSTS INTERNATIONAL) EAI, INC.
DENVER NFR FUEL SUPPLY COSTS AND IMPACTS 2011

INTRODUCTION
DISTRIBUTION SYSTEM IMPACTS
In this section, potential impacts of changes to the summer gasoline grade specifications are
discussed relative to potential changes to the supply of gasoline for the Front Range market. The
operation of the Colorado Front Range supply network was detailed as to current operations and
the linkage to primary supplying refineries was provided in the Overview section of this report. In
review, there are six primary supply refineries to the Colorado market area. These six refineries,
their locations and supply linkages are shown in Figure DST‐1 and described below:
Salt Lake
City
Figure DST‐1
Refined Product Supply – Pipelines and Refineries
Rocky Mountain Region and Colorado Front Range
Major Terminals
Refineries
(xx) Pipeline Capacity MBPCD
ID
Boise
Missoula
Twin Falls Pocatello
UT
* Primary Colorado Front Range Supply Refineries
Great Falls
Billings
WY
EAI, INC. (ENERGY ANALYSTS INTERNATIONAL) EAI, INC.
DENVER NFR FUEL SUPPLY COSTS AND IMPACTS 2011
CO
DST‐1
MT
Sheridan
Rock Springs
Casper
*
Denver
*
Fountain
Glendive
DS**
Valero Sunray
*
La Junta
Sidney
North
Platte
Kaneb (21)
ConocoPhillips Borger
* *
*
Copyright ©: EAI, Inc., 2011
Suncor, Commerce City, CO – located directly in Denver/North Front Range market
Frontier, El Dorado, KS – supplies Front Range via Magellan Chase pipeline to Aurora
Frontier, Cheyenne, WY ‐ supplies Front Range via Plains pipeline to Denver
Sinclair, Rawlins, WY – supplies Front Range via Denver Products pipeline to Henderson
ConocoPhillips, Borger, TX – supplies Front Range via ConocoPhillips pipeline to Denver
Valero, McKee, TX – supplies Front Range via NuStar and ConocoPhillips pipelines to Denver
Refiners with significant alternative market options include ConocoPhillips Borger, Valero McKee
and Frontier, El Dorado. These refineries have alternative markets of significant size and have
product pipeline connections to these markets. Similarly, these same refineries in supplying
significant volumes to alternative markets can chose to retract product from the alternative

DISTRIBUTION SYSTEM IMPACTS
markets and send these volumes to Denver up to available pipeline capacity. Refineries with
extremely limited alternative market options include Suncor Denver and Frontier Cheyenne
refineries. These refineries place a very large portion of their product in the Denver/North Front
Range market area and would probably sell or close their refinery if they decided not to make
process investments to produce the required product. Lastly, Sinclair Rawlins refinery places about
half of its manufactured gasoline into the Denver/North Front Range market and with construction
of the UNEV product pipeline could place product retracted from Denver into alternative markets
to the west without closing‐although likely realizing a much lower gasoline margin.
Responses to the changes in gasoline grade specifications can take a number of forms including
decisions to not supply the Front Range market and reduction in the volume of specification grade
gasoline and hence the volume supplied. Impacts of these decisions may be observed as retraction
of attainment area gasoline from outlying markets, higher prices for gasoline product in the
nonattainment area versus the attainment area, attainment area gasoline prices rising to levels
similar to those in the nonattainment area and experiencing supply upsets due to a shrinkage in
available fungible Denver/Front Range spec gasoline.
MARKET PRICE IMPACTS
Examination of the market pricing is useful from two viewpoints. First, price spreads of product
grades can be compared to the increased operating costs for a proposed product grade to see if
historical price spreads support the investment. Second, as a guide to the potential price impact of
moving to more expensive specification fuels, it is useful to examine the market price behavior of
other markets that have similar fuel grades. In this case, Kansas City and Detroit both require 7.0
psi low RVP gasoline in the summer and Chicago requires RFG year round. Product terminals in the
Kansas City and Detroit areas offer both 7.0 low RVP gasoline and conventional 9.0 psi gasoline in
the summer. Virtually all of the gasoline offered in the Chicago area terminals is RFG, but nearby
Rockford, IL has a terminal that has conventional gasoline.
WHOLESALE RACK PRICE SPREAD TO CONVENTIONAL GASOLINE, cpg
2006 2007 2008 2009
Denver Summer 7.8 psi gasoline over 9.0 psi 2.28 1.19 3.85 1.76
Denver 7.8 Rack Over Gulf Coast 7.8 Spot Net Tariff 20.4 25 8.95 6.66
Kansas City Summer 7.0 psi gasoline over 9.0 psi 9.7 16.7 20.7 6.9
Detroit Summer 7.0 psi gasoline over 9.0 psi 0.64 1.36 5.47 3.9
Chicago RFG rack vs Rockford conventional year‐round 8.9 6.9 8.6 6.8
Gulf Coast Spot 7.8 psi gasoline over 9.0 psi NA 2.87 4.7 4.01
In Denver, the spread of 7.8 gasoline over 9.0 is relatively small compared to the spread of Gulf
Coast spot 7.8 over Gulf Coast spot 9.0 gasoline. This suggests that 7.8 gasoline is readily available
to satisfy the 7.8 market but not saturating the 9.0 psi market.
In Kansas City, the summertime 7.0 psi low RVP gasoline has had a relatively extreme range of price
spreads relative to conventional gasoline at the same or nearby terminal racks. Assuming the costs
EAI, INC. (ENERGY ANALYSTS INTERNATIONAL) EAI, INC.
DENVER NFR FUEL SUPPLY COSTS AND IMPACTS 2011
DST‐2

DISTRIBUTION SYSTEM IMPACTS
to make 7.0 psi gasoline for the KC market are similar to estimates in this study, then it would
appear that the 7.0 market supply was tight in 2007 and 2008 thus product price differentials
covered incremental production costs. In 2009, the market differential averaged only 6.9 CPG
suggesting that 7.0 psi gasoline was long and potentially spilling over into the 9.0 psi market. In the
Detroit area, gasoline supply tends to be long (9.0 psi grade) and it would appear that 7.0 psi
gasoline pricing is realizing values that are gravitating to 9.0 values and likely don’t cover
incremental production costs. This would suggest that 7.0 psi gasoline supply in that market is
generally balanced or long.
The price spread of Chicago RFG to nearby conventional gasoline has been much more stable at 8.9
to 6.8 cpg. As shown in Figure DST‐2, the summertime price increases in the Denver rack prices
have supported the movement of Gulf Coast RBOB to Denver and blending it with ethanol.
Figure DST‐2
Reformulated Gasoline Market vs Conventional
Denver unleaded regular rack minus Gulf Coast spot RBOB laid into
Denver blended with laid-in Chicago spot ethanol
Over 2008 – 2009, the spread of Denver rack prices over laid in Gulf Coast RBOB blended
to RFG narrowed. Denver summer prices generally support laid in Gulf Coast RFG.
Denver CVG rack - GC RFG, cpg
30
25
20
15
10
5
0
-5
-10
-15
-20
-25
-30
JAN_06
APR_06
JUL_06
OCT_06
JAN_07
APR_07
JUL_07
OCT_07
JAN_08
APR_08
JUL_08
OCT_08
JAN_09
APR_09
JUL_09
OCT_09
JAN_10
EAI, INC. (ENERGY ANALYSTS INTERNATIONAL) EAI, INC.
DENVER NFR FUEL SUPPLY COSTS AND IMPACTS 2011
DST‐3
DEN UNL - GC RFG
Co py righ t ©: EAI, Inc., 2011
Overall, the observation is that historical price spreads between grades have generally covered the
operating and capital costs levels estimated for Denver new fuel products. At times, but not
always, the C5/C6 rejection costs also appear to be covered but involve significant price excursions.
If the new fuel products are short in supply‐tight, there can and has been extreme pricing volatility
reflecting the difficult for the market to be satisfied with not ability to substitute other grades.
With the market is long with these new fuel grades, the product can spill over into the more
abundant fungible grade pool and discounting takes place which often results in market price
differentials that don’t cover incremental operating costs. Most of these other markets have more
access to alternative sources of gasoline product than the Denver/Front Range market does. Thus
whether or not a particular supplier’s incremental operating costs will be covered by rack pricing,

DISTRIBUTION SYSTEM IMPACTS
hence passed on to the consumer, depends on whether the market is short or long on product
supply. Historically, the Denver and the U.S. market has been balanced to short such that these
costs have been recovered. This may not be true in the future as it depends on the supply demand
balance when the new specifications take place with important implications from a declining
demand environment and from supply shifts due to reduced manufactured supply and supply
shifts.
DISTRIBUTION SYSTEM IMPACTS
In general, the observation for the higher RVP fuel specification changes is that these specifications
can be accommodated by the primary refineries supplying the Denver NFR with mostly investments
in removal of C5/C6 from gasoline blend streams. Gasoline volume loss can be made up with some
combination of increased crude runs and retraction of product from other markets.
For the two lower RVP cases (7 psi no waiver CBOB and RFG), the potential for minimizing C5/C6
rejection losses increases to the point where building separate tankage and minimizing production
of the non‐attainment area fuel would have economic advantages. In these cases especially, the
tendency would be to minimize overflow of non‐attainment area gasoline into attainment areas.
Depending on the required investments, it is possible that Sinclair, Frontier Cheyenne and Frontier
El Dorado may chose not to make any investments or just make partial investments for producing
these products, see Figure DST‐3.
CHEVRON
POCATELLO
RVP 7.8
PHOENIX
AZ-CBG
BILLINGS
RVP 9.0
EVANSTON
ROCK SPRINGS
BILLINGS
SINCLAIR
GILLETTE
CASPER
Figure DST‐3
Colorado Front Range Gasoline Supply Envelope
Summer Period With 7.0 psi – No Waiver CBOB or RFG Requirement
Investment by Sinclair Highly Questionable, Maybe Also Frontier Cheyenne
PCTL
SLC
CHEYENNE
CASPER
EAI, INC. (ENERGY ANALYSTS INTERNATIONAL) EAI, INC.
DENVER NFR FUEL SUPPLY COSTS AND IMPACTS 2011
NEWCASTLE
CHEYENNE
DST‐4
Total Supply
RAPID Envelope
CITY
RVP 7.8
SLC
GRAND
JUNCTION
GRAND
JUNCTION FOUNTAIN
COLORADO SPR
CHASE
SUPERIOR LINCOLN
SALINA Envelope
DELPHOS
SCOTT CITY GREAT BEND
MCPHERSON TOPEKA
CO SPR-PUEBLO
LA JUNTA
DODGE CITY
WICHITA
EL DORADO
LAS VEGAS
BLOOMFIELD NOW IDLED
NUSTAR COP
MEDFORD
LAVERNE
PONCA CITYTULSA
FLAGSTAFF
FLAGSTAFF
ABQ
GALLUP
ALBUQUERQUE
SANTA FE
VALERO
MCKEE
TUCUMCARI
COP
BORGER
ENID
OKLAHOMA
OKLAHOMA CITY
CITY
AMARILLO
LAWTON
COP
GRAND ISLAND
NORTH PLATTE
SIOUX FALLS
MITCHELL
DONIPHAN
ABERDEEN
YANKTON
NORFOLKSIOUX
CITY
Primary Supply
COUNCIL BLUFFS
DFW
RFG
MILFORD
Copyright ©: EAI, Inc., 2011
In the case of Sinclair, the volume of gasoline product involved may be such that the summer

DISTRIBUTION SYSTEM IMPACTS
volume could be placed in other markets ‐Salt Lake City, Idaho, Spokane or Las Vegas. In this case,
Sinclair could obtain summer gasoline from other Front Range Suppliers as part of an exchange or
net purchase. In the case of Frontier Cheyenne refinery, the potential volume loss of summer
grade gasoline would necessitate significant volumes from outside sources (Magellan Chase, Valero
McKee via NuStar, or ConocoPhillips via ConocoPhillips pipeline). In the case of both Sinclair and
Frontier Cheyenne, they could still provide 9 psi summer grade gasoline while other refiners
outside Colorado could increase their volumes of non‐attainment area gasoline.
Overall, this would result in reduction of the amount of overflow of non‐attainment gasoline into
attainment areas which is estimated at 38 MBPD in Figure DST‐4.
Figure DST‐4
Movement of Gasoline Into Attainment Areas
Denver – NFR Supply 115.9 MBPD 7.8 Gasoline
SUPPLY ENVELOPE
NE_FRNGE
NE_REMOTE
NNATNM
NW_WY_SRCE
SE_FRNGE
SE_REMOTE
SOTHN_ACCESS
WSTR_REMOTE
WSTR_TRNS
17.6 WSTR_REMOTE
1.1 NW_WY_SRCE
9.9 WSTR_TRNS
EAI, INC. (ENERGY ANALYSTS INTERNATIONAL) EAI, INC.
DENVER NFR FUEL SUPPLY COSTS AND IMPACTS 2011
DST‐5
78.1 NNATNM
3.0 NE_FRNGE
0.8 SE_FRINGE
1.0 NE REMOTE
1.2 SE_REMOTE
Co py righ t ©: EAI, Inc., 2011
The total gasoline supplied into Colorado by attainment and non‐attainment area and by source is
shown in the table and Figure DST‐5 below. The total gasoline demand in the Northern Front
Range market is approximately 94 MBPD with 78 MBPD in the non‐attainment area and 16 MBPD
in the attainment area. The Western remote market is approximately 17.6 MBPD and is mainly
supplied out of Denver via truck and railroad sources.

DISTRIBUTION SYSTEM IMPACTS
SUPPLY SOURCE Area Demand Cum Demand
Denver Sourced NNATNM 78.1 78.1
Denver Sourced WSTR_TRNS 9.9 88.0
Denver Sourced SE_FRNGE 0.8 88.8
Denver Sourced SE_REMOTE 1.2 90.0
Dnvr‐Chyn Sourced NE_FRNGE 3.0 93.0
Dnvr‐Chyn Sourced NE_REMOTE 1.0 94.0
Fountain‐LaJunta Terminal Sourced SOTHN_ACCESS 23.6 117.6
Denver Segregated‐NM Source WSTR_REMOTE 17.6 135.2
GJ‐Sinclair Source NW_WY_SRCE 1.1 136.2
The total attainment market for gasoline in Colorado is 58 MBPD consisting of the Denver
peripheral markets (16 MBPD), the Colorado Springs‐Pueblo market that is supplied by the TX‐
Panhandle refineries and supply from the North (24 MBPD) and the Grand Junction‐Western Slope
market (18 MBPD).
Demand, MBPD
90
80
70
60
50
40
30
20
10
0
Figure DST‐5
Colorado Gasoline Distribution
by Ozone Attainment Status and Source
Core Denver
Sourced Markets
Supplied by Denver or
Alternative Gasoline
Sources
NNATNM WSTR_TRNS SE_FRNGE NE_FRNGE SE_REMOTE NE_REMOTE SOTHN_ACCESS WSTR_REMOTE NW_WY_SRCE
Demand 78.1 9.9 0.8 3.0 1.2 1.0 23.6 17.6 1.1
Cum
Demand
78.1 88.0 88.8 91.7 93.0 94.0 117.6 135.2 136.2
Demand Cum Demand
EAI, INC. (ENERGY ANALYSTS INTERNATIONAL) EAI, INC.
DENVER NFR FUEL SUPPLY COSTS AND IMPACTS 2011
DST‐6
Sourced from Alternative Sources
or Segregated Denver Product
(Grand Junction Area)
160
140
120
100
80
60
40
20
0
Cumulative Demand, MBPD
Copyright ©: EAI, Inc., 2011
Responses to changes in supply sourcing and availability of non‐attainment area gasoline can be
facilitated by interconnectivity of pipelines and terminals. In the Denver area, there is significant,

DISTRIBUTION SYSTEM IMPACTS
not 100%, connectivity of product terminals of the various supply sources, see Figure DST‐6. In
particular, the Sinclair Henderson terminal has supply connections from both the Suncor refinery
and the Magellan Chase pipeline.
RAIL
LOADING
SUNCOR
PLAINS
DUPONT
DENVER
SUNCOR
COP
PLAINS
NUSTAR
Figure DST‐6
Refined Product Supply Network
PLAINS 8
PRODUCT TERMINAL
PRODUCT PIPELINE
REFINERY
CHEYENNE
to DUPONT
PL AINS 8
COMMERCE CITY
to FOUNTAIN
Denver – Colorado Front Range
SINCLAIR 6
COM MERCE CI TY
PLAINS 6
SINCLAIR
HENDERSON
COP 8
NUSTAR 10
SINCLAIR 6
COP-6
Suncor refinery can deliver to COP,
NuStar, and Sinclair terminals
AURORA
to AURORA
LAJUNTA to DENVER
MAGELLAN
Jet From Suncor
MAGELLAN 10
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DENVER NFR FUEL SUPPLY COSTS AND IMPACTS 2011
DST‐7
DIA FUELING
MAGELLAN 10 Jet
SCOTT CITY
to AURORA
RAWLINS
SINCLAIR
S P
IN L
C A
L IN
A S
IR 8
6
PLAINS 8
CHEYENNE
FRONTIER
PLAINS
HENDERSON
SINCLAIR
PLAINS
DUPONT
SINCLAIR 6
COMMERCE CITY
SUNCOR
to DIA
REFINERY
NUS TAR - 10
from MCKEE
NUSTAR
COP
COLO SPRINGS
NUSTAR
FOUNTAIN
PLAINS
LA JUNTA
COP
AURORA
NUSTAR
MAGELLAN 10
Copy righ t ©: EAI, Inc., 2011
The Suncor Denver refinery is a key supply source for the Denver/North Front Range and provides
about a third of the total gasoline supply. Loss of this volume via a decision to not make the more
expensive, lower RVP gasoline product would be very hard to replace on a short term basis. In
general, this replacement product would have to come from Frontier El Dorado, ConocoPhillips
Borger and Valero McKee refineries with additional product being sourced in the Texas – Western
Louisiana Gulf Coast area via Explorer and Magellan pipeline systems. Currently, the Gulf Coast
refineries are a major supply source for RBOB gasoline (RFG blendstock for ethanol blending) and
for low RVP, sub‐octane gasoline blendstocks.

BIO
BIOFUEL SUPPLY DEMAND OUTLOOK
ETHANOL
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INTRODUCTION
BIOFUELS SUPPLY DEMAND OUTLOOK
Ethanol is a widely used motor gasoline blendstock in the United States and its use has been
growing. Originally, it was primarily used to extend the supplies of gasoline for energy
independence reasons, and, additionally, to support the agriculture industry. More recently, its use
has been mandated to support air quality initiatives. Current renewable fuels mandates will soon
require its use in all gasoline at the 10 percent level. Bio‐ethanol is an agricultural derived product,
and hence is a renewable source of fuel. It can be an economically attractive method of increasing
fuel supplies.
The supply of ethanol for blending into Colorado gasoline comes from numerous sources.
Generally these sources are located in Colorado or the Midcontinent. Ethanol manufacturing
capability across the U.S. generally has exceeded demand levels by a significant margin, though in
the future, because of the renewable fuels mandates, this may be less so. Mandates for cellulosic
derived ethanol (ethanol produced from the cellulosic and hemicellulosic material of woody plants,
rather than starch or sugar components of corn or sugar cane) will require a huge expansion in the
capacities of the ethanol plants able to produce this product.
A major consideration in the blending of ethanol into gasoline is the increased Reid Vapor Pressure
(RVP) of the resulting blended product. In general, the cost of manufacturing gasoline for blending
with ethanol increases as the mandated RVP of the final blended product is reduced. As a result,
the increasing stringency of any given fuel strategy chosen will have increasing costs associated
with it, depending on the ultimate gasoline specification product chosen.
ETHANOL OVERVIEW
Ethanol is widely used as a motor gasoline blendstock in the United States and Brazil, and together
both countries were responsible for 89 percent of the world's ethanol fuel production in 2009.
Most cars on the road today in the U.S. can run on blends of 10% ethanol and the use of 10%
ethanol blended gasoline is mandated in many U.S. states and cities including California, Hawaii,
Minnesota, Missouri, Oregon, and, in 2011, Florida. Under the Federal Renewable Fuels Standard,
EPA is charged with establishing the amount of renewable fuels that must be sold each year in the
U.S. and basically this mandates increasing amounts of ethanol be blended into gasoline. Recently,
EPA authorized the use of E15 blended gasoline in model year 2001 and newer vehicles.
Bioethanol is a form of renewable energy that can be produced from agricultural feedstocks. It can
be made from very common crops such as corn, sugar cane, potato, and manioc. In the U.S.,
ethanol is primarily made from corn. There has been considerable debate about how useful
bioethanol will be in replacing gasoline. Concerns about its production and use relate to increased
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BIOFUELS SUPPLY DEMAND OUTLOOK
food prices , large amount of arable land required for crops, as well as the energy and pollution
balance of the whole cycle of ethanol production, especially from corn. Recent developments with
cellulosic ethanol production and commercialization may allay some of these concerns.
Cellulosic ethanol offers promise because cellulose fibers, a major and universal component in
plant cells walls, can be used to produce ethanol. According to the International Energy Agency,
cellulosic ethanol could allow ethanol fuels to play a much bigger role in the future than previously
thought.
As mentioned earlier, ethanol use is mandated by Federal and many state and city governments.
Use of corn ethanol as mandated by EISA 2007 requires use of up to 15 billion gallons of corn
ethanol annually by 2015 that would provide about 10.5% of blend material for gasoline.
ETHANOL BLENDED GASOLINE
Blending ethanol into conventional gasoline increases the Reid Vapor Pressure (RVP) of blended
gasoline by about 1 psi. Current Denver/Front Range Colorado specifications for summer time
gasoline is for 7.8 psi RVP gasoline with a 1 psi RVP waiver for ethanol blended gasoline. This
means that ethanol can be blended into regular specification grade gasoline and the resulting
product is allowed a 1 psi RVP waiver on final blend RVP. Different states have somewhat different
specifications on summer grade gasoline RVP, generally 9 psi, 7.8 psi and 7.0 psi are the most
common. In order to make gasoline with lower RVP specifications, it is required that higher RVP
components such as normal butane or pentanes to be taken out of the gasoline pool and low RVP,
high octane components added, e.g. alkylate. Because the market pricing of butane and pentanes
is almost always lower than gasoline, removal of these components and addition of alkylate results
in a higher manufacturing cost of final gasoline product.
Blending ethanol into conventional gasoline is simpler when there is a 1 psi RVP waiver for the
resulting ethanol blended gasoline – with no 1 psi waiver a special low RVP gasoline blendstock
must be provided for blending with ethanol, i.e. two market grades of gasoline. With the waiver, a
standard conventional gasoline can be blended with ethanol and the blend can be legally
marketed. The existence of a 1 psi waiver was established in the original EPA gasohol fuel waiver.
Since any permissible increase in fuel volatility will result in increased evaporative hydrocarbon
emissions (an ozone precursor), individual states have the right to disallow this waiver if required
for air quality purposes. In states with no 1 psi waiver, a specially blended, low RVP gasoline
product (CBOB) has to be blended with ethanol such that the final blend meets RVP limits. In
general, CBOB manufacture requires removal of normal butanes or pentanes and greater amounts
of alkylates to be added to gasoline in order to produce a specification grade gasoline product to be
blended with ethanol that will be within the RVP standards. Reformulated Gasoline (RFG) is
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BIOFUELS SUPPLY DEMAND OUTLOOK
generally the strictest specification grade gasoline in that it requires both low RVP and more limited
amounts of components detrimental to emissions. As implied by the above, as the summer‐grade
gasoline moves from 9.0 RVP conventional gasoline with 1 psi waiver to CBOB’s with or without 1
psi waivers to reformulated gasoline blendstocks for oxygenate blending, then the manufacturing
costs increase due to the greater removal of lower cost, low RVP components (butane and
pentanes), the greater need for higher cost, low RVP, high octane components to blended (alkylate
or polymerization gasoline), and the greater need to remove other components such as benzene.
Currently the approved ethanol gasoline products are ethanol blends to 10 percent (E10), and E85
(eighty‐five percent ethanol). Only flexfuel vehicles can burn E85 and the marketplace use of E85
has been extremely limited to date. In order to accommodate the increased levels of mandated
RFS ethanol, the maximum ethanol blend will have to increase. In October 2010, EPA approved E15
for use in model year 2007 and newer vehicles. In January 2011, EPA approved E15 for use in
model years 2001 to 2006. Past the 10 percent blends of ethanol, the RVP response of ethanol
being blended into gasoline recedes such that higher blends of ethanol past E10 will require
somewhat less manipulation of the gasoline pool to achieve the appropriate RVP blended fuel
levels. This study, begun in 2009, did not consider impacts of E15 gasoline specifications.
CORN ETHANOL ECONOMICS
The price of corn ethanol is dependent on the price of corn, cost of natural gas, cost of enzymes,
yeast and other chemicals used and labor, material and various miscellaneous expenses. According
to corn ethanol industry estimates, one 56 pound bushel of corn will yield up to 2.7 gallons of
ethanol and 17.4 pounds of distiller’s dry grains (DDGS). Each gallon of ethanol is estimated to
require .038 MMBTU of natural gas. The cost of enzymes, yeasts and chemicals is estimated to be
around $.14/gal, and labor, maintenance and various expenses including depreciation add another
$.23/gal. Using current price of corn at $3.47/bushel, price of DDGS at $110/ton, natural gas price
at $4.73/MMBTU, the net cost of corn ethanol is estimated at $1.48/gal. The current price of corn
ethanol ($1.60/gallon Platts spot May 2010 average) is thus lower than wholesale price of gasoline
($2.04/gal May 2010 Platts Gulf Coast spot gasoline) providing positive economics for corn ethanol
manufacturers. However, ethanol has only 2/3 rd of the energy content of gasoline and would thus
require 51% more volume to provide equivalent amount of energy. A 10 percent ethanol blended
gasoline has 3.3 percent less BTU energy than unblended gasoline.
The price of corn ethanol has varied widely in last five years reaching up to $2.82/gal in July 2008.
Using the tax credits of $.45/gal, ethanol is cost effective as a gasoline blend material. At present,
ethanol would be cost effective even without the federal tax subsidy. However, there have been
periods during the past five years when the price of gasoline has been substantially lower than the
price of ethanol such that even with the tax subsidy, it was uneconomic for gasoline marketers to
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BIOFUELS SUPPLY DEMAND OUTLOOK
blend and sell the product. At this point (and others), marketers will buy RINS credits in order to
meet the mandated RFS requirements. But in general, the price of ethanol has been mostly lower
than the price of gasoline and thus blending ethanol can potentially reduce the cost of ethanol
blended gasoline and this reduction in price may be passed to the end consumer.
With technological advancements, bioethanol from grains and cellulosic materials are expected to
gain further cost efficiency and provide a cost effective alternative to petroleum based fuels.
ETHANOL BASED ENGINES
Ethanol is most commonly used to power automobiles, though it may be used to power other
vehicles, such as farm tractors, boats and airplanes. On an energy basis, ethanol (E100)
consumption in an engine would be approximately 51% higher than for gasoline since the energy
per unit volume of ethanol is 34% lower than for gasoline. However, the higher octane number
and resulting higher compression ratios in an ethanol‐only engine allows for increased power
output and better fuel economy than could be obtained with lower compression ratios. Ethanol's
higher octane rating allows an increase of an engine's compression ratio for increased thermal
efficiency. In one study, complex engine controls and increased exhaust gas recirculation allowed a
compression ratio of 19.5 with fuels ranging from neat ethanol to E50. Thermal efficiency up to
approximately that of a diesel fuel was achieved. This would result in the fuel economy of a neat
ethanol vehicle to be about the same as one burning gasoline.
BIOFUEL MANDATES
The Energy Policy Act (EPACT) of 2005 had provisions for mandated use of ethanol and other
renewable fuels that increased over time. Following on this act, in December 2007, Congress
passed the Energy Independence and Security Act (EISA 2007) that further increased the mandate
for renewable fuels. Provisions of the Renewable Fuels Standard under EISA 2007 include:
Increasing corporate average fuel economy (CAFE) standards to 35 miles per gallon by year
2020 from current standard of 25 MPG, a 40% increase.
Use of advanced biofuels that increase from 0.1 BGY in 2009 to 21 BGY by 2022.
Use of cellulosic biofuels (part of advanced biofuels) that increase from 0.1 BGY in 2010 to
16 BGY by year 2022.
Use of biomass based diesel that increases from 0.5 BGY in 2009 to 1 BGY by year 2012.
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Use of total renewable fuel for motor transportation and home heating oil to 9 billion
gallons per year (BGY) in 2008 increasing to 36 BGY by 2022.
Provisions in the EISA 2007 include a Renewable Fuels Standard (RFS) that began in 2006 at 4 BGY
under EPACT 2005 and increases to 15.2 BGY by 2012, as shown in the figure below. The act’s
ethanol provisions ultimately reach 36 BGY in 2022. EPA administers the RFS and each year
determines the volume % of ethanol required in gasoline sold. Details of EPA rules are provided
later in the Renewable Fuels Section of this chapter.
The use of ethanol and other biofuels under EISA 2007 is significantly increased as shown in Figure
BIO‐1.
Ethanol Mandate BGY
Figure BIO-1
Federal Mandate for Total Ethanol Use
Under EISA 2007
40
38
36
34
32
30
28
26
24
22
20
18
16
14
12
10
8
Mandate % of Gas
2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
Mandate 9.2 11.1 12.9 13.9 15.2 16.6 18.1 20.5 22.5 24 26 28 30 33 36
% of Gas 6.95 8.40 9.83 10.62 11.58 12.64 13.90 15.74 17.12 18.51 20.10 21.69 23.28 25.66 28.04
The new federal mandate for corn ethanol use is shown in Figure BIO‐2.
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BIO‐5
30.0%
28.0%
26.0%
24.0%
22.0%
20.0%
18.0%
16.0%
14.0%
12.0%
10.0%
8.0%
6.0%
4.0%
% of Total Gasoline
Copyright ©: EAI, Inc., 2011

Ethanol Mandate BGY
16
15
14
13
12
11
10
9
8
BIOFUELS SUPPLY DEMAND OUTLOOK
Figure BIO-2
Federal Mandate for Corn Ethanol
Use - EISA 2007 – Actual for 2008
Mandate % of Gas
2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
Mandate 9.1 10.5 12 12.6 13.2 13.8 14.4 15 15 15 15 15 15 15 15
% of Gas 6.80 7.57 8.63 9.03 9.40 9.79 10.18 10.57 10.53 10.49 10.46 10.42 10.38 10.35 10.31
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BIO‐6
11.0%
10.0%
9.0%
8.0%
7.0%
6.0%
5.0%
4.0%
% of Total Gasoline
Copyright ©: EAI, Inc., 2011
The new Federal bill puts strong emphasis on use of advanced biofuels including use of cellulosic
biofuels. Nearly 60 percent of the new RFS is to be met by advanced biofuels including cellulosic
biofuels by the year 2022. Projected use of cellulosic biofuels under the new mandate is shown in
following Figure BIO‐3.
Ethanol Mandate BGY
Figure BIO-3
Federal Mandate for Cellulose Ethanol
Use EISA - 2007
24
20
16
12
8
4
0
Mandate % of Gas
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
Mandate 0.1 0.25 0.5 1 1.75 3 4.25 5.5 7 8.5 10.5 13.5 16
% of Gas 0.07% 0.18% 0.36% 0.71% 1.24% 2.12% 2.99% 3.86% 4.89% 5.92% 7.29% 9.34% 11.03
14.0%
12.0%
10.0%
8.0%
6.0%
4.0%
2.0%
0.0%
% of Total Gasoline
Copyright ©: EAI, Inc., 2011

BIOFUELS SUPPLY DEMAND OUTLOOK
In May 2009, President Obama announced a new National Fuel efficiency policy that requires
average fuel economy standard of 35.5 mpg by 2016. This is a speedup of the CAFÉ standards under
EISA 2007 of 35 mpg by 2020.
One of the options for gasoline emissions reduction is the banning ethanol usage during the ozone
season. In determining the scope of this study, the RAQC and CDPHE considered the possibility of
including an option for seeking a summertime waiver from blending ethanol in the state of
Colorado. Although it was considered, this option was not included in this study as an emissions
control strategy for the following reasons.
Banning ethanol blending during the ozone season would conflict with the requirements of federal
Renewable Fuels Standards (RFS) as established under the Energy Policy Act of 2005 and later
expanded under the Energy Independence and Security Act of 2007. Under the RFS, refiners in the
United States are required to blend a certain amount renewable fuels into the transportation fuels
that they produce during a given year. For 2011, refiners are required to blend 13.95 billion gallons
of renewable fuels. This amount will increase in step‐wise fashion to 36 billion gallons of renewable
fuels in 2022. Given current renewable fuel supplies, the technological limitations of today’s
vehicle fleet, and the current gasoline distribution system infrastructure, this mandate must be met
almost exclusively through the blending of 10% ethanol into conventional gasoline (E10). Even at
current levels, to meet the RFS mandate using E10, refiners across the country must blend ethanol
in virtually all of the gasoline sold throughout the year. Accordingly, banning the use of E10 in the
non‐attainment area during the ozone season would prevent refiners serving the area from
complying with their legal obligations under the federal RFS. Developments such as the increased
availability of flex‐fuel vehicles that can utilize fuel with up to 85% ethanol, as well as the allowance
for 15% ethanol blending in non‐flex fuel later model year vehicles will, moving forward, reduce the
refiners’ need to rely almost exclusively on E10 blending to meet the RFS. Given the expected slow
pace of these developments, however, in conjunction with the increasing amounts of renewable
fuels that will be required to meet the RFS, year round ethanol blending will need to continue for
the foreseeable future.
Recognizing that banning ethanol is not a legally viable option in light of the federal RFS mandate, a
number of parties have suggested that Colorado could obtain a waiver from the federal RFS from
EPA. While the Energy Independence and Security Act did provide EPA with waiver authority, the
standards for granting such a waiver were set exceptionally high. Specifically, to grant a waiver,
EPA must determine that one of two conditions has been met:
There is inadequate domestic renewable fuel supply; or
Implementation of the requirement would severely harm the economy or
environment of a State, a region or the United States.
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Because the basis for the waiver in the case for Colorado would be to allow the banning of ethanol
during the summer months in order to achieve reduction of ozone precursor emissions, neither the
domestic supply condition, nor the provision requiring severe economic harm would apply. An
argument could be made that a waiver is justified in order to avoid harm to the environment. In
considering a 2008 waiver request from the State of Texas, EPA rejected an argument premised on
the increase in ozone from using ethanol blending, concluding that the modest increases in
ambient ozone levels that could result from the RFS mandate did not constitute severe harm as
required under the statute. In light of this, the possibility of obtaining a waiver of the RFS would
appear to be extremely remote.
In addition to being incompatible with federal RFS requirements, banning ethanol during the ozone
season will not provide any appreciable ozone reduction benefit beyond the benefit achieved
through elimination of the 1 pound ethanol waiver. In the context of ozone formation, ethanol
blending in and of itself is not detrimental. Rather, what is harmful is ethanol blending in
conjunction with the regulatory allowance of a 1 psi increase in RVP for E10 blended gasoline. If
the waiver were eliminated, E10 gasoline would be no more volatile than conventional gasoline,
and therefore the increase in ozone precursor emissions from the current use of E10 during the
ozone season could be fully mitigated without resort to an ethanol ban. Accordingly, and in light of
the incompatibility between an ethanol ban and compliance with the federal RFS, CDPHE and RAQC
staff did not include such a ban in the list of alternative strategies.
CURRENT ETHANOL USAGE
Due to tax incentives, pricing of ethanol and the need for gasoline blendstocks, the use and
blending of ethanol is running slightly ahead of the mandate under EISA 2007. Under the EISA 2007
mandate, use of corn derived ethanol is estimated to increase from 6% currently to 10.5% of
gasoline by 2015 and then flatten thereafter. Experts estimate this level of corn ethanol
production is achievable without affecting other uses of corn as a feedstock.
Estimated consumption of ethanol in conventional and reformulated gasoline and oxygenated
gasoline for year 2009 for U.S. PAD Districts is summarized below.
U.S. ETHANOL SUPPLY ‐ DEMAND ‐ 2009
MBPD PADD I PADD II PADD III PADD IV PADD V Total
Production 9 674 13 10 7 713
Imports 9 0 1 0 2 12
Refiner/Blender Input 261 204 75 14 106 660
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Colorado is in PADD IV which produces less ethanol than is blended and as a result domestic
ethanol is railed or trucked to the area. EAI, Inc. estimates that Renewable Fuels Standard (RFS)
will require a blending ratio exceeding 10% of gasoline in very near future. EPA has been evaluating
this so called issue of “Blend Wall” and to authorize blending ethanol in excess of the current limit
of 10% and allow use of up to 15% (E15) ethanol. As noted previously, EPA has recently announced
authorization for using E15 in 2001 to current model year vehicles. In Colorado, ethanol usage in
gasoline as gasohol (10 percent blend) reported to the Department of Revenue was 146 million
gallons or 68 percent of the total gasoline distributed was 10 percent ethanol blended. Anecdotal
information and CDPHE Front Range gasoline survey data indicates that the amount of gasohol sold
is substantially higher.
TAX INCENTIVE FOR ETHANOL
The American Jobs Creation Act of 2004 extended the ethanol tax incentive of 51 cents per gallon
of ethanol blended i.e. 5.1 cpg credit on 10 percent ethanol gasoline. Only registered blenders can
apply for this excise tax refund. It allowed ethanol producing farm cooperatives to pass the tax
credit to its farmer owners. Passage of Volumetric Ethanol Excise Tax Credit (VEETC) provides a
similar 51 cents per gallon tax credit for every gallon on ethanol used for E85 i.e. 43.35 cpg on
blended E85. The VEETC, now at 45 cpg since 2008, was due to expire at the end of 2010 but was
extended through 2011. EPACT 2005 increases the small ethanol producer definition from 30 to 60
million gallons per year and allows a 10 cpg tax credit with a cap of 1.5 million dollars. It also
established a tax credit of 30% or up to $30K for the cost of installing clean fueling infrastructure
i.e. retail pumps. Numerous state level tax incentives and funding programs exist. In Colorado
there is no state ethanol sales tax credit program.
CELLULOSIC ETHANOL
Cellulosic ethanol is a biofuel produced from lignocellulose, a structural material that comprises
much of the wood, grasses, or the non‐edible parts of plants. Corn stover, switchgrass, organic
wastes, woodchips and the byproducts of lawn and tree maintenance are some of the more
popular cellulosic materials for ethanol production. Ethanol production from lignocellulose has the
advantage of abundant and diverse raw material compared to sources like corn and cane sugars,
but requires a greater amount of preprocessing to make the sugar that is typically used to produce
ethanol by fermentation.
Switchgrass and agricultural residue such as corn, wheat and rice straw are the major biomass
materials being studied today, due to their high productivity as well as availability. Cellulose,
however, is contained in nearly every natural, free‐growing plant, tree, and bush, in meadows,
forests, and fields all over the world without agricultural effort or cost needed to make it grow.
According to U.S. Department of Energy studies conducted by Argonne National Laboratory, one of
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the benefits of cellulosic ethanol is that it reduces greenhouse gas emissions (GHG) by 85% over
reformulated gasoline.
Ethanol from wood was first made in Germany in 1898. It involved the use of dilute acid to
hydrolyze the cellulose to glucose, and was able to produce 18 gallon per ton, which was later
improved to 50 gallons per ton. During World War II, the US contracted Vulcan Copper and Supply
Company to construct and operate a plant to convert sawdust into ethanol. The plant was based
on modifications to the original German Scholler process as developed by the Forest Products
Laboratory. This plant achieved an ethanol yield of 50 gal/dry ton but was still not profitable and
was closed after the war.
With the rapid development of enzyme technologies in the last two decades, the acid hydrolysis
process has gradually been replaced by enzymatic hydrolysis. However, chemical pretreatment of
the feedstock is required to separate hemicellulose for robust enzymatic conversion of cellulose to
sugar. A sulfite pretreatment method to break down lignocellulose for robust enzymatic hydrolysis
of wood cellulose has recently been developed.
EISA 2007 has mandated 36 billion gallons per year of renewable fuels by 2022. The renewable
fuels mandate caps the mandated maximum production of ethanol from corn starch at 15 billion
gallons per year, and proposes a mandate of 16 billion gallons per year of cellulosic biofuels in
2022. To meet the RFS, the U.S. Departments of Agriculture (USDA) and Energy (DOE) are
developing advanced biofuels that use switchgrass, corn stover and other cellulosic materials.
Much of this work has been conducted at the DOE’s National Renewable Energy Laboratory (NREL)
in Golden Colorado. In March 2007, the U.S. government awarded $385 million in grants aimed at
ethanol production from nontraditional sources. Half of the six projects chosen will use thermo‐
chemical methods and the other half will use enzymatic ethanol methods.
ETHANOL DEMAND OUTLOOK
NATIONAL
The outlook for RFG and oxygenated gasoline consumption is shown in Figure BIO‐4. Current U.S.
consumption of 2.9 million BPD is forecasted to slightly decline to 2.85 million BPD by 2010 due to
current economic recession. Ethanol consumption forecast under new federal mandate is shown in
Figure BIO‐5. U.S. ethanol consumption is currently running slightly ahead of federal mandate
under RFS. Some 7.6 million flex‐fuel vehicles (FFV), capable of burning ethanol blends up to 85%
(E85) are in use today. Over nineteen hundred E85 retail outlets are in operation. Based on
current ethanol consumption and projected capacity buildup, EAI, Inc. estimates that ethanol will
constitute about 8.4% of gasoline in 2009 and continue to increase under new federal mandate as
shown previously in Figure BIO‐1.
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BIO‐10

MBPD
BIOFUELS SUPPLY DEMAND OUTLOOK
Figure BIO-4
U.S. Gasoline Consumption Forecast
Reformulated & Oxygenated Fuels
3500.0
3000.0
2500.0
2000.0
1500.0
1000.0
500.0
0.0
Gas Oxy Gas RFG
2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
Gas RFG 2870.0 2966.0 2958.6 2967.0 3020.0 3002.0 3033.0 2964.0 2906.0 2850.0
Gas Oxy 312.0 294.0 307.1 313.7 315.2 291.0 270.0 0.0 0.0 0.0
Beyond 2007 oxygenates included in RFG
Figure BIO-5
U.S. Gasoline Consumption Forecast
Based on Federal Ethanol Mandate (EISA 2007)
MBPD
11000
10000
9000
8000
7000
6000
5000
4000
3000
2000
1000
0
Ethanol Net Gasoline
2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
Net Gasoline 8562 8050 7898 7749 7658 7554 7442 7315 7140 7006 6872 6724 6576 6430 6219 6010
Ethanol 424 601 724 845 910 989 1077 1181 1334 1447 1561 1691 1821 1952 2147 2342
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EAI, Inc. estimates that 10% ethanol blend reduces U.S. crude import by 7.7%, assuming 66% of
crude used in the United States during 2008 was imported, as shown in the table below. In terms
of state usage, Minnesota has set an ethanol requirement in gasoline of 20%, effective 2013. This,
of course, is dependent on the EPA permitting the blending of fuel ethanol at this level for the
majority of the automotive fleet. Growing interest in E85 (85% ethanol and 15% gasoline) may
further increase use of ethanol. Ford and GM have committed to produce more flexible fuel
vehicles (FFV) that run on both gasoline and E85. New federal mandate under EISA 2007 calls for
use of ethanol at 10% of gasoline usage by 2012 increasing to 24% by 2022.
MBPD 2008 2009 2010 2011 2012
EPACT 2005 MANDATE 352 398 444 483 489
5.7% BY VOLUME 493 491 490 488 487
10% BY VOLUME 865 862 859 857 854
EISA 2007 MANDATE* 601 646 845 910 989
*Actual consumption for Jan‐Oct 2009.
ETHANOL SUPPLY OUTLOOK
PROJECTED U.S. ETHANOL USAGE
Ethanol production facilities currently in operation and those under construction are listed in Table
BIO‐1. Many of the larger, more efficient plants are in the control of a group of companies of
which, Archer Daniels Midland is the largest. A very large portion of the remaining ethanol
production is widely dispersed as small plants. Smaller plants, besides being less efficient as
measured in terms of manufacturing costs, are also less reliable particularly in the early years of
operation. Because of this, the ethanol industry has a track record of ethanol plant turn over, with
the newest, largest, most efficient plants replacing the smaller, older, less efficient ones, especially
when ethanol price margins are narrow or negative.
The ethanol industry has a strong track record of building new capacity as needed. Over the last
five years, annual capacity has increased at 25% per year. However new construction slowed in
2009 due to overcapacity and gasoline demand stagnation resulting from economic recession.
Industry estimates indicated over four billion dollars was invested in new plants and plant
expansion in 2008. In terms of corn crop utilization, in 2008 as in 2007, the ethanol industry used
18% of the U.S. total corn crop, most of which was feed corn, not corn for direct human
consumption. Because of multiple issues, such as increased fuel and energy costs, as well as
increasing consumption for the available corn production, corn prices doubled in the last couple of
years from around $2.40/bushel in early 2006 to over $6/bushel in early 2008. Since then prices
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BIOFUELS BUSINESS OUTLOOK 2011
BIO‐12

BIOFUELS SUPPLY DEMAND OUTLOOK
have moderated and are currently at $3.75/bushel. However the high price situation is short term
as significant acreage is available for corn production that was not used in previous years or was
being used for other crops. According to USDA, ethanol production increased the price a farmer
receives from corn by 25% to 50%. A DOE study indicates that U.S. corn production can take care
of the RFS mandated requirements.
New ethanol production capacity needed for corn and advanced biofuels under EISA 2007 is shown
in Figure BIO‐6. As shown, additional corn ethanol capacity is needed starting 2010 that increases
to 1.1 BGY by 2015. Based on the past ethanol industry track record, EAI, Inc. estimates this
additional level of corn ethanol production is achievable.
Figure BIO-6
New Capacity for Corn & Advanced Biofuels
Needed U.S. Fuel Ethanol Mandate
Corn ethanol capacity needed is above existing and new capacity under construction.
BGY
26
24
22
20
18
16
14
12
10
8
6
4
2
0
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
Total Cap 0 0.3 1.3 2.5 3.9 5.5 7.8 9.6 11.3 13.3 15.3 17.3 20.3 23.3
Corn Eth 0 0 0.0 0.5 1.1 1.7 2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3
Advanced Biofuels 0 0.315 1.35 2 2.75 3.75 5.5 7.25 9 11 13 15 18 21
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BIO‐13
Copyright ©: EAI, Inc., 2011
New production capacity needed for advanced biofuels such as cellulosic ethanol is also shown in
Figure BIO‐6. EAI, Inc. estimates that as a result of tax incentives as well as research and
development incentives, significant amounts of advanced biofuels will be produced starting in
2012. The potential of ethanol production using cellulose material is estimated at 18 BGPY, fifty
percent above that of corn based ethanol. This is an extremely ambitious goal for a product that

BIOFUELS SUPPLY DEMAND OUTLOOK
has never been produced in large quantities commercially. Whether the proposed mandate of 21
BGY of advanced biofuels by 2022 will be achieved appears uncertain.
EAI, Inc. tracks ethanol plants in operation and undergoing expansion, new plants under
construction, and new plant announcements. In order to derive an outlook for ethanol production
capacity, EAI, Inc. categorized the announced plants as to their likelihood of proceeding. The
distribution of these plants is shown in Figure BIO‐7. As shown, the ethanol industry is highly
concentrated in the U.S. Central Corridor.
ETOH_PLNT_PRD_FC
CONSTRUCTION
STATUS (RANK)
EXIST_BASE (128)
NEW_BASE (102)
SPEC_1_BASE (86)
SPEC_2_BASE (73)
SPEC_3_BASE (8)
Data as of January 2008
Figure BIO-7
U.S. Ethanol Production Outlook
Plant Construction Activity
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BIO‐14
Copyright ©: EAI, Inc., 2011
As shown figuratively in Figure BIO‐8, existing U. S. plant capacity at the end of 2008 was 698 MBPD
(10.6 BGY). Adding the capacity of plants under construction increases total plant capacity to 896
MBPD by 2008. Capacity of the existing and planned plants to be built by the end of 2009 is more
than adequate to take care of 989 MBPD ethanol demand as mandated under the RFS through
2012. EAI Inc. has developed several scenarios for regional bio‐fuels supply, demand and logistics
outlook. The forecast beyond 2009 is based on a preliminary assessment of a likely future ethanol
supply scenario. EAI, Inc. has also assumed in its production forecast that cellulose based ethanol
will begin to contribute commercial quantities of supply in 2012 while corn based production
flattens out due to flatting mandated requirements and corn supply constraints.

BIOFUELS SUPPLY DEMAND OUTLOOK
Figure BIO-8
U.S. Fuel Ethanol Existing and Under Construction
Estimated Capacity vs Projected Demand
Production, MBPD
3000
2500
2000
1500
1000
500
0
US CENTRAL CORRIDOR ETHANOL PRODUCTION FORECAST, MBPD
CATEGORY 2006 2007 2008 2009 2010 2011 2012
EXIST_BASE 252.4 340.6 319.1 349.5 378.2 386.5 386.5
NEW_BASE 88.5 88.5 298.5 374.7 405.6 414.4 414.4
SPEC_1_BASE 0.0 0.0 37.4 569.1 604.7 694.9 694.9
SPEC_2_BASE 0.0 0.0 4.9 12.1 495.8 548.3 548.3
SPEC_3_BASE 0.0 0.0 5.4 5.7 6.1 105.3 105.3
TOTAL 429.1 665.3 1311.2 1890.4 2149.4 2149.4
LIKELY PRODUCTION 429.1 655.0 1293.3 1388.5 1495.8 1495.8
Exist & New Base
Proceeding; Spec 1
likely & Spec 2-3
uncertain
EXIST_BASE
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BIOFUELS BUSINESS OUTLOOK 2011
BIO‐15
SPEC_1_BASE
NEW_BASE
SPEC_3_BASE
SPEC_2_BASE
2006 2007 2008 2009 2010 2011 2012
SPEC_3_BASE 0.0 0.0 5.4 5.7 6.1 105.3 105.3
SPEC_2_BASE 0.0 0.0 5.5 28.3 556.1 615.0 624.8
SPEC_1_BASE 0.0 0.0 37.4 620.4 662.2 762.8 762.8
NEW_BASE 92.2 108.5 395.1 490.1 500.8 500.8 500.8
EXIST_BASE 265.1 425.1 375.9 406.9 415.7 415.7 415.7
TOTAL DEM 315 424 585 724 845 910 989
Copyright ©: EAI, Inc., 2011
The U.S. has potential to produce 1.3 billion dry tons of cellulosic biomass per year, which has the
energy content of four billion barrels of crude oil, which translates to over 50% of current US oil
consumption. This however is dependent on the successful commercialization of cellulosic biomass
to fuel ethanol process. Currently this process is more expensive than traditional starch and sugar
ethanol production, and it is yet to be determined at what price crude oil and wholesale priced
gasoline have to be to break even.
In 2010, there were 20 cellulosic ethanol projects are under development and construction in the
U.S. as shown in the Table BIO‐2. These projects use various kinds of feedstock including
switchgrass, corn stover, wood waste, softwood chips and forest residue as well as municipal solid
wastes, unrecyclable paper, tree, yard and vegetative wastes. Total capacity of these plants is
estimated at 280 MMGY providing just enough capacity to meet 2011 mandate. The cellulosic
ethanol mandate rises rapidly to 500 MMGY in 2012, 3 BGY in 2015 and 7 BGY in 2018. Meeting
these ambitious mandates would require more aggressive schedule of new plant construction,
development of other advanced biofuels or scaling down of the mandates.
In June 2006, a U.S. Senate hearing was told that the current cost of producing cellulosic ethanol is
US $2.25 per US gallon. At that price, it would cost about $120 to substitute a barrel of oil, taking

BIOFUELS SUPPLY DEMAND OUTLOOK
into account the lower energy content of ethanol. At the same hearing, the Senate was told that
the research target was to reduce the cost of production to US $1.07 per US by 2012. Currently at
the laboratory level ethanol from cellulose has been developed at a cost of $1.25 to $1.70 per
gallon. However, these processes need further development to make ethanol at commercial
volumes at these production costs. Currently corn ethanol gets a tax incentive of 45 cents per
gallon of ethanol blended into gasoline. Each gallon of cellulosic ethanol has equivalence value of
2.5 gallons of corn ethanol for RFS purposes. EPACT 2005 and continuing under EISA 2007 include
several incentives to produce cellulosic ethanol. A separate $1.01/gal tax credit is available for
producing advanced cellulosic biofuels. Thus strong incentives are in place to produce cellulosic
ethanol.
ETHANOL LOGISTICS AND PRICING
ETHANOL LOGISTICS
Most of the existing and new ethanol plants are located in the Midwest. In 2009, over 94 percent
of the total U.S. ethanol production was in the U.S. Central Corridor and especially concentrated in
the Midwest. With the initiation of mandated ethanol blending under the RFS, most of the ethanol
is blended into fuels in existing reformulated gasoline markets in the California, the Northeast, Gulf
Coast and Chicago. Most of these markets already had significant installed capital for receiving,
storing and blending ethanol into gasoline. However, it is important to note that this entails
significant movements of ethanol from the U.S. Central Corridor to these outlying markets.
An overview of the EAI, Inc.’s estimates of major ethanol flows is shown in Figure BIO‐9. Flows in
this figure were derived from an ethanol supply demand balance where ethanol blended into
gasoline can be a major unknown depending on reporting by state agencies. As shown, major flows
of ethanol from the U.S. Central Corridor are to the West Coast 94 MBPD, Gulf Coast 60 MBPD and
Northeast/Southeast 237 MBPD. In the future, ethanol movements will hinge on saturation of the
blending market in the Midwest/U.S. Central Corridor. An indication of the saturation is the
number of companies posting ethanol blended and unblended gasoline at the various USCC
markets as mapped in Figure BIO‐10. The U.S. Central corridor is shown to be approaching a high
degree of saturation, especially in the major markets. Also shown in Figure BIO‐9 are levels of
foreign import ethanol into the U.S. The Northeastern seaboard including Florida had the highest
level of foreign imports at 11 MBPD. Caribbean nations, processing Brazilian feedstocks, are the
primary import source.
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BIO‐16

DMD: 103
PRD: 6
WC
BIOFUELS SUPPLY DEMAND OUTLOOK
EAI, Inc. U.S. Ethanol Balances
Jan-Oct 2009, MBPD
EXPORT TO WC: 94 MBPD
RM
DMD: 14
PRD: 10
4
MBPD
DMD: 72
PRD: 11
GC
Figure BIO-9
USCC
DMD: 200
PRD: 648
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60
MB
PD
1 MBPD
Figure BIO-10
BIO‐17
237 MBPD
SES
NES
DMD: 257
PRD: 9
11 MBPD
Relative Market Terminal Ethanol Saturation
Relative Saturation
Market TRM Shares
Ethanol is transported into California primarily by railcars and occasionally by marine tankers.
Union Pacific Railroad is the primary rail carrier for ethanol and BNSF is the second major carrier of
ethanol to California. Ethanol is transported to Gulf Coast region by BNSF Railroad and to Eastern
Seaboard states by CSX. Waterborne ethanol is transported from the Midwest primarily by barges
to Gulf Coast ports such as New Orleans and then loaded into product tankers, mostly in the 30
MDWT size range. After delivery to end market petroleum distribution terminals, ethanol is
blended with gasoline just prior to the gasoline being shipped to the retail stations.
PCT_ETOH
1
0.5
0.1
PCT NO ETOH
Copyright ©: EAI, Inc., 2011
Copyright ©: EAI, Inc., 2011

BIOFUELS SUPPLY DEMAND OUTLOOK
Several ethanol unit train facilities have recently been built across the country. These include
facilities in Northern and Southern California, Dallas‐Fort Worth, New York harbor, Boston,
Maryland and Virginia. These new facilities have significantly reduced transportation related
ethanol supply problems. Unit train off‐loading facilities built in Florida, Georgia and South
Carolina have alleviated supply problems to the Southeast. Other proposed unit train facilities
include those at Las Vegas, Portland OR, Louisiana, and additional facilities in Texas.
Estimates of transportation costs from the Midwest to Los Angeles via rail are 20 to 24 cpg while
rail cost to the Gulf Coast is estimated at 16 cpg and to New York Harbor at 14 cpg. Tanker
transportation cost from Gulf Coast to West Coast is estimated at 10 to 13 cpg, making total
transportation cost from Midwest to west Coast by rail and tankers at 24 to 27 cpg. Thus
transportation cost using barge/tankers is 5 to 7 cents per gallon higher than by rail cars only.
Incremental marine tanker unloading charges would add another 1 cent per gallon to the cost
making marine transportation cost 6 to 8 cents per gallon more than rail car transportation cost.
Waterborne movement of ethanol also takes more time. Currently most of the ethanol shipped to
U.S. destinations is by trains, as shown in the table below, with occasional shipments over water.
ORIGIN
TRANSPORTATION COST ANALYSIS
RAILCAR RATE
DESTINATION
($/BBL)
MINNEAPOLIS PORTLAND 10.46 24.9
MINNEAPOLIS LOS ANGELES 9.42 22.4
MINNEAPOLIS SAN FRANCISCO 11.99 28.5
MINNEAPOLIS HOUSTON 7.99 19.0
CHICAGO PORTLAND 11.98 28.5
CHICAGO LOS ANGELES 8.79 20.9
CHICAGO SAN FRANCISCO 11.39 27.1
CHICAGO HOUSTON 7.57 18.0
CHICAGO DETROIT 3.93 9.4
CHICAGO BOSTON 6.24 14.9
CHICAGO NEW YORK 5.71 13.6
CHICAGO WASHINGTON DC 7.72 18.4
CHICAGO MEMPHIS 5.57 13.3
CHICAGO CHARLOTTE 6.59 15.7
CHICAGO JACKSONVILLE FL 6.95 16.5
CHICAGO MIAMI FL 8.50 20.2
DES MOINES SEATTLE 10.94 26.0
DES MOINES PORTLAND 10.94 26.0
DES MOINES SAN FRANCISCO 10.34 24.6
DES MOINES LOS ANGELES 7.74 18.4
DES MOINES SALT LAKE CITY 10.07 24.0
DES MOINES PHOENIX 9.61 22.9
DES MOINES DENVER 6.52 15.5
DES MOINES CORPUS CHRISTI 9.94 23.7
DES MOINES HOUSTON 6.61 15.7
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BIO‐18
RAILCAR RATE
(CENTS/GAL)
Ethanol is moved from marine and rail terminals to the marketing terminals by truck. Neat ethanol
is currently not moved by pipelines because of the effect of ethanol has on pipe and pump seals
and the ability of ethanol to adsorb water from the pipeline and other liquids. While in the past the

BIOFUELS SUPPLY DEMAND OUTLOOK
conditioning of product pipelines and pipeline operations has held back the transportation of fuel
ethanol through product pipelines, this is changing. Some refiners with their own pipelines are
experimenting with transporting ethanol through their pipelines. One of the biggest hurdles to
transporting ethanol through gasoline and distillate pipelines is to ensure that the pipelines stay
dry, with little residual water and the right ethanol resistant seals are used. The biggest concern is
water. At certain concentrations of water, a phase separation of the ethanol from gasoline occurs.
Under the right conditions, the ethanol physically leaves the gasoline‐ethanol mixture to mix with
the water layer instead. Kinder Morgan has recently started batching denatured ethanol on its
Tampa to Orlando pipeline. Given the large volumes of fuel ethanol that need to be transported, a
number of ethanol pipelines are being considered – including one from the Midwest to the
Northeast U.S.
ETHANOL PRICING
With the advent of mandated ethanol blending and greatly increased production, as well as market
demand, pricing of ethanol has gone through some dramatic changes. Spot prices of ethanol,
gasoline and diesel fuel relative to WTI spot are plotted in Figure BIO‐11. Prior to 2005, ethanol
prices were higher than crude and product prices due in part to many large states and areas such
as California and the northeast states, switching from the use of MTBE in their reformulated
gasoline programs to ethanol. Since then, ethanol prices have been very volatile and with the
surge in ethanol production in 2007 and 2008, the spread of spot ethanol prices to crude prices had
become negative indicating over‐supply relative to demand/blending capability, then recovered in
2010 only to go negative again in latter 2010.
WTI Crude Price, $/Bbl
Figure BIO-11
Spot Product Price Spreads to Crude
Chicago Spot Gasoline and Diesel to WTI
160
140
120
100
80
60
40
20
0
WTI_CSH Gasoline Diesel Ethanol
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BIO‐19
100
80
60
40
20
0
-20
-40
Product Spread to WTI, $/Bbl
Copyright ©: EAI, Inc., 2011

BIOFUELS SUPPLY DEMAND OUTLOOK
For ethanol, a very important parameter is the ethanol blending incentive calculated as the price of
posted rack finished blended gasoline minus 0.9*CVG rack (or RBOB spot) price minus
0.1*delivered ethanol price plus 4.5 (5.1 to 2008) cpg blending tax credit. As shown in Figure BIO‐
12, the ethanol blending incentive for RFG has consistently been positive. The incentive for
blending into rack conventional gasoline turned consistently positive in 2Q07 with lower ethanol
prices and stayed mostly positive.
Incentive, Cents Per Gallon
80.00
70.00
60.00
50.00
40.00
30.00
20.00
10.00
0.00
-10.00
-20.00
Figure BIO-12
Ethanol Blending Incentive
CHICAGO CLEVELAND DETROIT PITTSBURGH ST. LOUIS TAX INCENTIVE
JAN_04
APR_04
JUL_04
OCT_04
JAN_05
APR_05
JUL_05
OCT_05
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BIOFUELS BUSINESS OUTLOOK 2011
BIO‐20
JAN_06
APR_06
JUL_06
OCT_06
JAN_07
APR_07
JUL_07
OCT_07
JAN_08
APR_08
JUL_08
OCT_08
JAN_09
APR_09
JUL_09
OCT_09
JAN_10
Copyright ©: EAI, Inc., 2011
In terms of supply and distribution to outlying markets, Chicago is the generally accepted pricing
reference point for ethanol. In the past four years, spot pricing of ethanol has been published for a
number of major ethanol blended gasoline markets in the U.S. – New York Harbor, Houston Gulf
Coast and Los Angeles (notably also major reformulated gasoline markets). Rail transportation
rates from Chicago to these markets are shown in Figure BIO‐13 and the market margins for New
York, Houston and Los Angeles relative to Chicago origin ethanol are shown in Figure BIO‐14. The
ethanol market margins observed for New York Harbor and the Gulf Coast were higher than Los
Angeles but are running closer over the last two years.

BIOFUELS SUPPLY DEMAND OUTLOOK
Ethanol Transportation Rates To Major Markets
U.S. Rail and Brazil Origin Waterborne, cents per gallon
Import ethanol would be most competitive in Florida market.
Pacific
NW
Pacific
SW
Chicago Origin Rail Rates – Transportation Plus Car Leasing
Rocky
Mountain
9.2
Figure BIO-13
Northern
Tier
Gulf
Coast
Mid-
Continent
Brazil Origin Tanker Rates – World Scale Clean Product Rate
NY/FL are 75 MDWT and TX/CA are 30 MDWT.
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BIO‐21
To New York Harbor
Midwest 13.6
Southeast
Seaboard
7.0
4.7
4.5
Brazil
Ethanol Market Margins –Chicago Origin
Houston and New York Harbor spot markets yield better netbacks than West Coast even though
these port markets have better access to import ethanol. Most foreign ethanol imports land in
Northeast and Southeast U.S. , followed by Pacific Southwest and Gulf Coast.
Market Margin to Chicago, cpg
60
55
50
45
40
35
30
25
20
15
10
5
0
-5
-10
-15
-20
JAN_06
MAR_06
MAY_06
JUL_06
SEP_06
NOV_06
JAN_07
MAR_07
Figure BIO-14
Gulf Coast New York Los Angeles
MAY_07
JUL_07
SEP_07
NOV_07
JAN_08
MAR_08
MAY_08
JUL_08
SEP_08
NOV_08
JAN_09
MAR_09
MAY_09
JUL_09
SEP_09
NOV_09
JAN_10
MAR_10
MAY_10
JUL_10
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Copyright ©: EAI, Inc., 2011

BIOFUELS SUPPLY DEMAND OUTLOOK
As shown in Figure BIO‐9, the Northeast is the location of the largest volumes of foreign import
ethanol into the U.S. followed by Houston and the West Coast. Excepting small volumes from
Canada, all of the U.S. imports of ethanol originate in South American and Caribbean countries and
the ethanol production is usually sugarcane based. Brazil is the major direct supplier of ethanol to
the U.S. (7.7 MBPD in 2008) and also supplies significant volumes of wet ethanol to be dehydrated
in the Caribbean Basin Initiative counties. Caribbean Initiative Basin countries supplied 13.5 MBPD
of ethanol to the U.S. in 2008. By going through the CBI countries, companies can avoid the duties
associated with imports from non‐CBI countries (54 cpg, 2.5% duty, subject to quota and origin
content limitations). Market margins for Brazilian ethanol imports into the Northeast are shown in
Figure BIO‐15 along with monthly import volumes. As U.S. production has increased and logistical
improvements have been made, the attractiveness of Brazilian ethanol imports has declined as
have the volumes. Removing the 54 cpg duty on ethanol would significantly change this. Florida is
ramped up for ethanol blending in 2008 and this market would be the most attractive market,
transportation wise, for South American/CBI import ethanol. In response to the U.S. import duty
on ethanol, Brazil also increased its export price via a tariff – overall result was a cessation of direct
imports of ethanol from Brazil.
Brazil Ethanol Imports – Northeast Ports
Price spread calculated as NYH spot ethanol minus Brazil spot minus
transport minus duty (54 cpg and 2.5%)
Peaks in imports during summer. Imports have fallen off as U.S. production has grown
and price spreads have become negative – import tariff impasse between U.S. and Brazil.
NYH - Laid in Brazil, cpg
30
20
10
0
-10
-20
-30
-40
-50
-60
-70
JAN_06
MAR_06
MAY_06
JUL_06
SEP_06
NOV_06
JAN_07
MAR_07
MAY_07
JUL_07
SEP_07
NOV_07
JAN_08
MAR_08
Figure BIO-15
Import Volumes NYH - Laid in Brazil
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BIOFUELS BUSINESS OUTLOOK 2011
BIO‐22
New Brazil 20 %
makes imports
uneconomic
MAY_08
JUL_08
SEP_08
NOV_08
JAN_09
MAR_09
MAY_09
JUL_09
SEP_09
NOV_09
JAN_10
MAR_10
MAY_10
JUL_10
100
90
80
70
60
50
40
30
20
10
0
Monthly Import Volume, MBPD
Copyright ©: EAI, Inc., 2011

RENEWABLE FUELS STANDARD OVERVIEW
BIOFUELS SUPPLY DEMAND OUTLOOK
The Renewable Fuel Standard (RFS) program is required by the EPACT 2005 (Section 1501). It
mandated increasing renewable fuel use from 4 Billion Gallons/Year beginning in 2006 to 7.5 Billion
Gallons /Year by 2012. These targets have now been superseded by EISA requirements, which have
substantially increased them. As part of the adoption of the original RFS program, EPA was
authorized by congress to develop rules to implement the RFS standards. EPA proposed
comprehensive implementation plan in September 2006 and invited public comments. Based on
comments received, the final rule was drafted and then published on May 1st 2007.
The program was effective September 1, 2007. The RFS standard for 2009 was 8.4% of gasoline
sold. It applies to any party that produces gasoline in the 48 states, or imports gasoline into the 48
states (Hawaii opted in January 2008), and includes blenders that produce gasoline from
blendstocks. Producers and importers of gasoline are called Obligated Parties. Exporters of
renewable fuel are not obligated parties, but they do have Renewable Volume Obligations (RVO) as
explained later.
NEW RFS REGULATIONS
INTRODUCTION
In May 2009, EPA proposed revisions to the National RFS program to address changes as required
by the EISA 2007. As stipulated under EISA 2007 the revised statutory requirements establishes
specific volume standards for cellulosic biofuel, biomass‐based diesel, advanced biofuel, and total
renewable fuel that must be used in transportation fuel each year. The revised statutory
requirements include new greenhouse gas emission (GHG) thresholds for renewable fuels. The
regulatory requirements for RFS will apply to domestic and foreign producers and importers of
renewable fuel.
GREENHOUSE GAS REDUCTION THRESHOLDS
EISA 2007 established new renewable fuel categories and eligibility requirements, including setting
the first ever mandatory GHG reduction thresholds for the various categories of fuels. For each
renewable fuel, GHG emissions are evaluated over the full lifecycle, including production and
transport of the feedstock; land use change; production, distribution, and blending of the
renewable fuel; and end use of the renewable fuel. The GHG emissions are then compared to the
lifecycle emissions of 2005 petroleum baseline fuels (base year established as 2005 by EISA)
displaced by the renewable fuel, such as gasoline or diesel. The lifecycle GHG emissions
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BIO‐23

BIOFUELS SUPPLY DEMAND OUTLOOK
performance reduction thresholds as established by EISA range from 20 to 60 percent reduction
depending on the renewable fuel category.
LIFECYCLE GHG THRESHOLDS SPECIFIED IN EISA
(PERCENT REDUCTION FROM 2005 BASELINE)
RENEWABLE FUEL *20%
ADVANCED BIOFUEL **50%
BIOMASS‐BASED DIESEL 50%
CELLULOSIC BIOFUEL 60%
*The 20% criterion generally applies to renewable fuel from new facilities that
commenced construction after December 19, 2007.
**EPA is proposing to exercise the 10% adjustment allowance provided for in EISA
for the advanced biofuels threshold to as low as 40%.
For renewable fuels to qualify, they must meet or exceed these minimum GHG reduction
thresholds.
TREATMENT OF REQUIRED VOLUMES IN 2009
Under the RFS1 regulations as stipulated in EPACT 2005, the annual percentage standards that are
applicable to obligated parties are determined by a formula set forth in the regulations. The
formula uses gasoline volume projections from the Energy Information Administration (EIA) and
the required volume of renewable fuel provided in Clean Air Act section 211(o)(2)(B). Since EISA
modified the required volumes in this section of the Clean Air Act, it is the new statutory volumes
that must be used under the RFS1 regulations in generating the standards for 2009. As a result EPA
published the new total renewable fuel volume of 11.1 billion gallons as the basis for the 2009
standard, and not the 6.1 billion gallons that was required under EPACT 2005. The RFS standard in
2009 will continue to be applicable to producers or importers of gasoline and only for the volume
of gasoline that they produce or import.
While this approach applies the total renewable fuel volume standard of 11.1 billion gallons
required by EISA for 2009, the RFS1 regulatory structure does not provide a mechanism for
implementing the 0.5 billion gallon requirement for biomass‐based diesel. Therefore, EPA is
proposing to address this issue by increasing the 2010 biomass‐based diesel requirement by 0.5
billion gallons and allowing 2009 biodiesel and renewable diesel RINs to be used to meet this
combined 2009/2010 requirement since 2009 biomass based diesel standards were not specified in
time for implementation.
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FINAL STANDARDS FOR 2010
BIOFUELS SUPPLY DEMAND OUTLOOK
As the RFS2 (EISA 2007) program is implemented, EPA expects to conduct a notice‐and‐comment
rulemaking process each year in order to determine the appropriate standards applicable in the
following year. EPA plans to issue a notice of proposed rulemaking (NPRM) in the spring and a final rule
by November 30 of each year as required by statute. However, EPA proposed the 2010 standards in its
May 2009 notice. EPA issued a final rule on February 3, 2010 setting the applicable standards for 2010.
For 2010 total renewable fuels standard of 12.95 billion gallons is unchanged. However within the total
RFS, volumes of cellulosic biofuel and advanced biomass diesel volumes are changed. Final 2010
standards are shown below:
Fuel Category
Standards for 2010
Percentage of Fuel
Required to be Renewable
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Volume of Renewable Fuel
(in billion gal)
Cellulosic biofuel 0.004% 0.0065
Biomass‐based diesel *1.10% *1.15
Total Advanced biofuel 0.61% 0.95
Renewable fuel 8.25% 12.95
Based on recent market analysis considering information from pilot and demonstration scale
plants, the EPA has set the 2010 cellulosic biofuel standard of 6.5 million gallons vs EISA 2007 target
of 100 million gallons. While this is a significantly less volume than that set forth in EISA, a number
of companies and projects appear to be poised to expand production over the next several years.
For biomass based diesel, EPA combined the 2010 biomass based diesel requirement of 0.65 billion
gallons with the 2009 biomass based diesel requirement of 0.5 billion gallons to require obligated
parties meet a combined 2009/2010 requirement of 1.15 billion gallons by the end of 2010
compliance year.
PROGRAM DESIGN AND PROPOSED IMPLEMENTATION APPROACH
EPA proposes to continue to use the Renewable Identification Number (RIN) system currently in
place to track renewable fuels and determine compliance with modifications designed to
implement the EISA provisions. At the same time, EPA sought comments on several provisions
aimed at enhancing the RIN system based on their experience to date. Any changes would apply
starting January 1, 2010. The current RFS1 regulations would continue to apply until EPA issues

BIOFUELS SUPPLY DEMAND OUTLOOK
new regulations to implement RFS2. Therefore, regulated parties will continue to be subject to the
existing regulations at least through December 31, 2009, or later if the effective date of the RFS2
program implementation is delayed.
OVERVIEW OF IMPACTS OF THE RULE
EPA conducted analysis to determine the economic impacts of the RFS2 rule on energy security,
fuel costs, petroleum consumption, greenhouse gases, the agricultural sector and emissions
affecting air and water quality. RFS2 standards are expected to reduce dependence on foreign
sources of crude oil, increase domestic sources of energy, and diversify our energy portfolio to help
in moving beyond a petroleum‐based economy, while at the same time providing important
reductions in greenhouse gas emissions such as carbon dioxide that affect climate change. The
increased use of renewable fuels such as ethanol, biodiesel and other renewable fuels is also
expected to have the added benefit of providing an expanded market for agricultural products such
as corn and soybeans and open new markets for the development of cellulosic feedstock industries
and conversion technologies. As the requirements of EISA are implemented, EPA will continue to
assess these impacts to assess wider public policy considerations of renewable fuels.
The proposed rule also includes substantial analysis for when EPA anticipates ethanol production to
exceed the volume that can practically be blended into gasoline nationwide at 10 volume percent
level (E10), known as the “blend wall.” The 10% per gallon by volume limit in gasoline is based on
the original “gasohol waiver” which was included in the Clean Air Act of 1978. The analysis includes
a discussion of distribution issues for E10, E85, and potential mid‐level blends such as E15, and how
distribution issues may affect when the blend wall is reached.
GREENHOUSE GAS EMISSIONS
For the first time in a regulatory program, lifecycle analysis of GHG emissions is being utilized to
establish those fuels that qualify for the different renewable fuel standards. Based on lifecycle
analysis, EPA believes that the expanded use of renewable fuels would provide significant
reductions in GHG, such as carbon‐dioxide emissions over time. Based on a combined use of
various models, EPA analyzed the lifecycle GHG emissions for a number of pathways for producing
the increased volumes of renewable fuels that are mandated by EISA. The incremental volumes of
each biofuel type were then evaluated to determine their average impact on GHG emissions
compared to the 2005 baseline petroleum fuel they would be displacing.
EPA estimates that greater volumes of biofuel mandated by RFS2 will reduce GHG emissions from
transportation by a total of 6.8 billion tons CO2 equivalent when measured over a 100 year
timeframe and discounted at 2%. This is equivalent to approximately 160 million tons CO2
equivalent per year. These reductions would be primarily in the form of carbon dioxide, with small
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BIOFUELS SUPPLY DEMAND OUTLOOK
contributions from other greenhouse gases. The reductions would be equivalent to taking about
24 million vehicles off the road.
EMISSIONS AND AIR QUALITY
The increased use of renewable fuels also affects air pollutant emissions, with some pollutants such
as evaporative hydrocarbons, nitrogen oxides (NOx), acetaldehyde and ethanol expected to
increase and other pollutants such as carbon monoxide (CO) and benzene expected to decrease.
EPA projects that proposed RFS2 program will result in significant increases in ethanol and
acetaldehyde emissions, increasing the total U.S inventories of these pollutants by 30%‐40% in
2022 relative to emissions resulting from the RFS1 mandate. EPA projects more modest increases
in NOx, formaldehyde, particulate matter, evaporative hydrocarbons, acrolein, and sulfur dioxide.
EPA projects a decrease in ammonia (NH3) emissions (due to reductions in livestock agricultural
activity), CO (due to impacts of ethanol on exhaust emissions from vehicles and non‐road
equipment), and benzene (due to displacement of gasoline with ethanol in the fuel pool). It should
be noted that these general results may be altered locally by impacts from ethanol plants,
petroleum refineries and other sources of air pollution.
EPA’s estimates of the emissions impacts of the RFS2 program took into account both
“downstream” emissions from vehicles and engines and “upstream” emissions from the production
and distribution of the fuel. According to EPA, the atmospheric chemistry related to ambient
concentrations of PM2.5, ozone and air toxics is very complex, and making predictions based solely
on emissions changes is extremely difficult. Therefore it plans to conduct Full‐scale photochemical
air quality modeling to characterize the air quality and health impacts of the program in the final
rule.
The RFS Program is implemented using a Renewable Identification Number (RIN), a discussion
of which follows.
RENEWABLE IDENTIFICATION NUMBER (RIN)
Under RFS, a RIN is assigned to every gallon of BioFuel produced or imported into the United
States. RIN is comprised of 38 digits, and serves as a serial number which is tracked throughout its
life in the renewable fuel supply chain, from the point of production to the point at which the fuel
is placed into the retail market.
Required information about the fuel and its producer is embedded within the 38‐digit code that
makes up the RIN. Following are the key information provided in RIN:
Status of the RIN as far as being tradable as a separated credit.
The year the fuel was produced ‐ also referred to as the vintage.
Who produced or imported the renewable fuel.
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Where it was produced or imported into the U.S.
What kind of fuel, ethanol, biodiesel, etc.
Its equivalence value – Whether it comes from cellulosic or other advanced
technologies
And the total volume of credits assigned to a batch of renewable fuel
RINs are used for tracking renewable fuel at every step of the supply chain. The process starts when
renewable fuel is produced or imported and the 38‐digit serial number is assigned to the fuel.
Tracking and quarterly reporting to EPA is made as the fuel is transferred from supplier to customer
and so on. Once the renewable fuel is placed into the retail market the RIN is separated from the
fuel and then serves as a tradable credit. This separated RIN, or credit, is then available for trading
in open market, similar to other environmental credit trading programs. The K code or the first digit
of the 38 digit RIN denotes whether the RIN is assigned (K code 1) i.e. attached to physical gallon or
unassigned or used as a tradable credit (K code 2)
RIN is used to demonstrate to EPA that a party has met their particular obligation under the RFS.
EPA requires each party in the supply chain report their RIN activity to the agency on a quarterly
basis. The advanced fuel standard (RFS2) under EISA 2007 requires that the frequency of reporting
increases first to monthly and then to near real‐time, or within three days of transfer. It is
mandatory that RINs be generated by each producer or importer of more than 10,000 gallons of
renewable fuel. To generate a RIN a producer or importer needs to gather the required data
pertaining to their entity, facility, and product type. Then as fuel is produced or imported a unique
batch number for the applicable year and the total volume of RINs are added to the 38‐digit series
resulting in what EPA defines as the parent batch RIN. The upcoming implementation of the RFS2
program is expected to bring major changes to the way RINs are assigned to produced and
imported product as the current rules have generated numerous errors in RIN generation. EPA
expects to eventually issue RIN numbers as producers and importers submit operational data
directly to EPA in a more real‐time manner.
Producers and importers of gasoline are called obligated parties. Companies identified by EPA as
“obligated parties” must meet the mandated standards in order to remain compliant with federal
RFS. By far the biggest portion of obligated parties are refiners, such as ExxonMobil, ConocoPhillips,
Valero, BP, Shell, and Chevron. Other companies that fall under the RFS obligated party
classification would be importers of gasoline into the U.S. as well as companies that buy petroleum
intermediate components and blend at facilities like fuel terminals to produce finished gasoline.
Under the regulations, each of these obligated parties is then required by the law to use their pro‐
rata share of renewable fuel, published by EPA each year. Each obligated party multiplies their on‐
road gasoline production times the RFS percentage for the year to determine their obligation. This
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is called their RVO or renewable volume obligation. Under RFS2 volume obligation will extend to
non‐road gasoline as well as to locomotive and marine fuels.
Obligated parties demonstrate to EPA that they have met or exceeded their RVO by the submission
of RINs each year. These RINs can be acquired through the process of purchasing and blending
renewable fuel into their own pool of petroleum products or by acquiring RINs from another party
that has blended renewable fuel in excess of their RVO and is willing to sell their RINs to the
obligated party. Central to the RFS program are provisions for credit banking and trading, with the
RIN serving as the paper credit for this purpose.
As title to products and associated RINs are transferred from one party to the next, each party is
required to keep record of the transaction and report the transactions to EPA, two months after
end of each quarter. EPA utilizes a post‐audit approach to the program, where they gather data
pertaining to literally millions of transactions and then process, looking for discrepancies and
inconsistencies among the data. The problem with this approach is that possible violations are
revealed months after they occur creating enforcement problems.
An alternative approach used by companies is to voluntarily participate on the renewable fuel
registry where they use a centralized registry to conduct a more through job of tracking and
assignment and minimize ownership issues before they occur. For RFS2 EPA has proposed a
centralized and closed system for clearing RIN transactions known as the EPA Moderated
Transaction System (EMTS) – scheduled to go into effect in 2011.
The advanced standard, RFS2, has been expanded to encompass both gasoline and diesel fuels,
refined or imported. This will result in inclusion of several more parties who currently are not
obligated under RFS1.
After more than two years of RIN market activity, several companies in the supply chain are yet to
participate in the RIN program due to the complexity of the rules and the expense associated with
compliance programs. This has created problems in RFS enforcement.
The parties who have incentive to own tradable RINs are domestic refiners or importers of gasoline
into the United States. With the free market trade of unassigned RINs, speculators and traders are
now actively involved in the RIN market, having interest in acquiring RINs for the purpose of
hedging a market position or for speculative financial gain. During last two years swings in the
tradable RIN market has been extreme, with 300 percent plus price moves in some cases. This
indicates need for more liquidity in the market which is expected to happen over time with
experience.
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BIOFUELS SUPPLY DEMAND OUTLOOK
Digits two through five of RIN show the vintage year when the RIN is generated. According to the
regulations, a RIN can be used to demonstrate compliance in the year in which it was generated or
the year that follows its year of generation. However, the RINs submitted from the prior year
vintage cannot exceed 20 percent of the total RIN submission for the current compliance year.
Many factors affect RIN values that include current year’s mandate of renewable fuel to the level of
overall confidence in the marketplace. The following is a list of possible contributing factors to the
value of a RIN:
RFS mandate – The mandated level of renewable fuel, under RFS1 and RFS2 for the
specific year establishes the demand and therefore influences price.
Transportation cost – The cost to transport ethanol and other biofuels play a key role
in the overall RIN value.
Waiver petitions and other uncertainties that await EPA’s ruling have proven to have
a dramatic impact on RIN prices.
Vintage year – Current vintage year RINs will have more value than RINs from the
prior year due to limitations on the use of prior year RINs.
Blending Margins – The net economic margin considering petroleum product price,
biofuel price, and other blending tax credits has a direct impact on the availability of
RINs and consequently the price.
RIN failures – Invalid RINs in the market place result in oversupply of RINs and
consequently drive the price of RINs down and with it the demand for physical
product.
Deadlines – The year end deadline and the overall readiness by industry can result in
last hour panic and a resulting price increase.
Since the start of the RIN trading on Sept.1, 2007 RIN prices have seen dramatic increases. RIN
credits originally traded at 0.25 cents each. As traders have gotten more experience and have
understood the value of RINs, it has traded for over 25 cents each, a multiple of 100 times.
RFS2 regulations in the future will have several types of RINs in the marketplace – depending upon
specific types of RINs. For example, cellulosic RINs (Type C RINs) will have a different value than
RINs derived from say corn ethanol (Type R RINs – also known as renewable fuel RINs).
EISA 2007 has special consideration for Cellulosic RIN in that RINs derived from cellulosic biofuels
(Type C RINs), will have a floor price of not less than 25 cents per RIN, and possibly more depending
upon the rack price of gasoline in any given year.
Expected changes under RFS2 when compared to the original RFS1 include:
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BIOFUELS SUPPLY DEMAND OUTLOOK
Under RFS2, mandated volumes apply to both gasoline and diesel used in both on‐road
and off‐road application in the United States. RFS1 obligations apply only to on‐road
gasoline.
RFS2 mandates increased dramatically over RFS1, 36 BGY by 2022 vs. 7.5 BGY by 2012.
RFS2 provides for “carve outs” for specific fuel types, namely biodiesel and cellulosic
biofuels.
RFS1 places a 15 BGY cap on the mandates for corn starch derived ethanol.
RFS2 addresses greenhouse gas (GHG) contribution by establishing four categories of
fuels and requiring threshold performance requirements to be met. RFS1 did not
address GHG reduction.
RFS2 places restrictions on land use in an attempt to address the food vs. fuel
argument. These restrictions require renewable fuel producers to qualify their
feedstocks each time they generate RINs.
The above list gives a good indication of the change in complexity that the industry faces as the
legislators and the regulators become more involved with the day to day business of transportation
fuels. One example of such complexity is that under RFS2 there are 4 categories of renewable fuels,
each with their own distinct RIN type. This would require obligated parties will now have to meet 4
different standards instead of just one renewable fuel standard as today. They will need to acquire
and monitor 4 different RIN types to be assured of compliance with the regulations.
COLORADO ETHANOL AND BIODIESEL OUTLOOK
EAI, Inc. projects Colorado gasoline demand to increase from 137 MBPD in 2009 to 142 MBPD in
2010 and very slowly decline through 2020. Under RFS2, total ethanol content of gasoline is
estimated to increase from 6.8% in 2009 to 15.8% in 2017, consisting of 11.6% corn ethanol and
4.2% cellulosic ethanol as shown in Figure BIO‐16. Total ethanol demand is estimated to increase
from 9.5 MBPD in 2009 to 21.9 MBPD in 2017 that includes 16 MBPD of corn ethanol and 5.8 MBPD
of cellulosic ethanol as shown in Figure BIO‐17. Net gasoline requirement over this period falls to
around 116 MBPD, thus requiring no additional gasoline production capacity.
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BIOFUELS SUPPLY DEMAND OUTLOOK
Figure BIO-16
Estimated Federal Mandate Percent of Total
Gasoline for Colorado Ethanol Use (EISA 2007)
Initially program based mostly on corn based ethanol production but this levels off in 2015
to 11.5% –assumes technology and plants available to produce cellulosic ethanol.
Ethanol Mandate % of Total Gasoline
Ethanol Mandate MBPD
16.00%
14.00%
12.00%
10.00%
8.00%
6.00%
Corn Based Total Ethanol
2009 2010 2011 2012 2013 2014 2015 2016 2017
Corn Based 6.80% 9.10% 9.60% 10.10% 10.50% 11.00% 11.50% 11.50% 11.60%
Total Ethanol 6.80% 9.20% 9.80% 10.40% 11.30% 12.40% 13.80% 14.80% 15.80%
26
24
22
20
18
16
14
12
10
8
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New Cellulosic Based
Ethanol
Figure BIO-17
Estimated Federal Mandate for Colorado
Ethanol Use (EISA 2007)
Initially program based mostly on corn based ethanol production but this levels off in 2015
to 16 MBPD –assumes technology and plants available to produce cellulosic ethanol.
Corn Based Total Ethanol
New Cellulosic Based
Ethanol
2009 2010 2011 2012 2013 2014 2015 2016 2017
Corn Based 9.6 13 13.6 14.3 14.9 15.5 16.1 16 16
Total Ethanol 9.6 13.1 13.9 14.7 16 17.5 19.4 20.6 21.9
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BIOFUELS SUPPLY DEMAND OUTLOOK
Current ethanol production capacity in Colorado is estimated at 10 MBPD plus another 16 MBPD
capacity is planned. If planned capacity is built, it would take care of Colorado ethanol needs
through 2017. Within 400 miles of Denver North Front Range area, 40 MBPD of current capacity is
available to meet ethanol demand as shown in Figure BIO‐18. Within neighboring Tri‐state area of
Colorado, Kansas and Nebraska total ethanol demand through 2017 can be met by less than 1/3rd
of available capacity leaving the remaining 2/3rd of the capacity for export to other states. This is
displayed in Figure BIO‐19.
Capacity MBPD
300
250
200
150
100
50
0
Figure BIO-18
Denver Front Range Ethanol Supply
Availability by Distance (Miles)
Adequate current capacity available within 300 miles to take care of federal mandates
through 2017.
Current Cap Total Cap
100 200 300 400 500
Current Cap 3 8 23 40 90
Total Cap 9 33 77 182 290
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Planned capacity
Copyright ©: EAI, Inc., 2011
Figure BIO-19
Total Corn Ethanol Demand for Tri State (CO-KS-NE)
Area vs. Current Production Capacity
Adequate current capacity exists to take care of ethanol demand through 2014. Projected ethanol
demand is less than 24% of current capacity.
Total Corn Ethanol Demand under RFS2 (MBPD)
36
32
28
24
20
16
Demand % of Cap.
2009 2010 2011 2012 2013 2014
Demand 19 26 27 29 30 32
% of Cap. 14% 18% 20% 21% 22% 23%
24.0%
22.0%
20.0%
18.0%
16.0%
14.0%
12.0%
% of Current Capacity
Copyright ©: EAI, Inc., 2011

BIOFUELS SUPPLY DEMAND OUTLOOK
EISA 2007 contains a mandate for biomass diesel use that increases from .5 BGY in 2009 to 1 BGY in
2012. The usage level beyond 2012 is to be determined by the EPA Administrator. Federal
mandate RFS2 for biodiesel translated for the state of Colorado amounts to biodiesel usage of 378
BPD in 2009 increasing to 1305 BPD in 2017, resulting in 2.1% of projected diesel use as shown in
Figure BIO‐20. As shown in Figure BIO‐21 current biodiesel capacity of 1700 BPD is available within
100 miles of Denver North Front Range area to take care of the demand through 2017.
Figure BIO-20
Estimated Federal Mandate for Colorado
Biomass Diesel Use Under EISA 2007
Biomass diesel use as a % of total estimated diesel use increases from .3% to 2.1%.
Biomass Diesel Mandate BPD
Capacity MBPD
1400
1300
1200
1100
1000
900
800
700
600
500
400
300
200
Mandate % of Diesel
2009 2010 2011 2012 2013 2014 2015 2016 2017
Mandate 378 502 631 805 986 1058 1134 1216 1305
% of Diesel 0.70% 0.90% 1.10% 1.40% 1.70% 1.80% 1.90% 2.00% 2.10%
Figure BIO-21
Denver Front Range Biodiesel Supply
Availability by Distance (Miles)
Adequate current capacity available within 100 miles to take care of federal
mandates through 2017.
6
5
4
3
2
1
0
Current Cap Total Cap
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Planned capacity
100 200 300 400 500
Current Cap 1.7 2.87 2.87 2.87 2.87
Total Cap 2.41 3.59 4.37 5.02 5.02
3.0%
2.7%
2.4%
2.1%
1.8%
1.5%
1.2%
0.9%
0.6%
0.3%
0.0%
% f l i l
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BIOFUELS SUPPLY DEMAND OUTLOOK
Major ethanol plants in Colorado Front Range area: Major ethanol plants in Colorado and
neighboring states is shown in Table BIO‐3. Below is a description major projects.
Great Western Ethanol, Evans CO: Plans to build an ethanol plant south of Greeley, CO. Originally
sized at 50 MMGY the plant was doubled in size to 100 MMGY. Construction of the plant is delayed
for over five years due to economic recession and build up of overcapacity in ethanol production.
Once construction is under way, it could take between 18‐24 months to complete the plant.
Front Range Energy, Windsor, CO: Front Range Energy located in Windsor, Colorado, began
ethanol production in June 2006. The plant processes approximately 40 million gallons of ethanol
and 396,000 tons of wet distillers grain annually.
Sterling Ethanol, Sterling CO: Sterling Ethanol LLC built the first ethanol plant in the state of
Colorado. The plant has design capacity to produce 42 million gallons of ethanol annually.
Expansion plans are being pursued which will bring the capacity to 80 million gallons annually. In
addition to ethanol, the plant produces approximately 350,000 tons of distiller’s wet grain. The
plant started up in November 2005. The plant has 30 employees and operates 24 hours a day. Each
day 42,000 bushels of corn are used in ethanol production.. Sterling Ethanol LLC is owned by 26
investor groups made up primarily of local agriculture producers and business owners.
Yuma Ethanol, LLC Yuma, CO: Yuma Ethanol, LLC is a privately held company categorized under Industrial
Organic Chemicals manufacturers and located in Yuma, CO. It started ethanol production in January 2007.
Current capacity is 40 MMGY.
Merrick and Company, Golden CO: Merrick has a facility associated with Coors Brewery in Golden CO to
recover ethanol from brewery waste. Capacity is 3 MMGY.
Nexsun Ethanol, Walsh, CO: Nexsun Ethanol bought an idled 3 MMGY ethanol plant in Walsh CO and has
plans to expand and restart the plant.
Panhandle Ethanol LLC , Lancaster County, NE: This planned ethanol plant has estimated capacity of 8
MMGY to 10 MMGY using hemi‐cellulosic feedstock. This project is on hold until industry conditions
improve.
Bridgeport Ethanol, Bridgeport, NE: Bridgeport Ethanol LLC (Bridgeport, Nebraska), an affiliate of Sterling
Ethanol LLC (Sterling, Colorado), started up grinding corn, the first stage of ethanol production, at a new
plant near Bridgeport during the first week of October 2008. The plant has a rated capacity of 45 MMGY.
Central Bio‐Energy Ethanol, Imperial, NE: Has a manufacturing plant for ethanol with a capacity of
100 Million Gallon Per Year.
Mid‐America Bioenergy, Madrid NE: Has an ethanol manufacturing plant with a capacity of 44 Million
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Gallon Per Year. Current plans for expansion to 88 MMGY are on hold.
Wauneta Economic Development, Wauneta NE: The company has plans to build a 100 MMGY
capacity corn ethanol plant. The project is on hold until industry conditions improve.
Arkalon Energy LLC, Liberal KS: Arkalon Energy LLC is a privately held company that owns and
operates a ethanol manufacturing plant located in Liberal, KS. The plant has rated capacity of 110
MMGY. The company was established in 2006 and incorporated in Kansas. Current estimates show
this company has annual revenue of $7,000,000 and employs a staff of approximately 35.
Cornhusker Energy , Lexington, NE: Cornhusker Energy is a privately‐held company with an ethanol
plant in Lexington, NE. The company currently produces more than 40 million gallons of ethanol
annually using locally grown corn as feedstock. The company employs 44 individuals, and currently
purchases more than 15 million bushels of corn annually from local producers and grain dealers, In
addition to ethanol; Cornhusker Energy produces both wet and dry distillers grains, providing a
feed source for local livestock producers.
Construction is currently in the works to expand the plant to 150 million gallons.
Major biodiesel plants in Colorado Front Range area – Major biodiesel plants in the tri state area
is shown in Table BIO‐4. Following is a description of major plants.
Rocky Mountain Biodiesel Industries Berthoud, Colorado: Rocky Mountain Biodiesel facility near
Denver CO incorporates the latest automated technology in biodiesel production. It is capable of
producing up to 3 million gallons of biodiesel per year using wide variety of feedstocks. The plant
started up in October 2004 and is currently in operation.
Blue Sky Biodiesel, Cheyenne, WY: Blue Sky Biodiesel in Cheyenne, Wyo., produces 5 million
gallons of biodiesel annually. The plant produces fuel made from soybean oil that is trucked in from
eastern Nebraska. The Cheyenne plant employs about 12 workers.
Pioneer Biodiesel Gering, NE: The plant produces 12 million gallons of biodiesel using soybean oil
as feedstock.
Prospect Biodiesel Bennett, CO: The plant produces 4 million gallons of biodiesel using soybean oil
as feedstock.
Sunrise Biodiesel Grant, NE: The plant produces 10 million gallons of biodiesel. Two additional
plants are on the horizon. The producing plants procure soybean oil from South Dakota and
Nebraska.
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Table BIO‐1
U.S. FUEL ETHANOL PRODUCTION CAPACITY (EXISTING AND UNDER CONSTRUCTION)
MILLION GALLONS PER YEAR (MMGY)
EAI RGN COMPANY
LOCATION
CITY ST
GC ABENGOA BIOENERGY CORP PORTALES NM 1‐Jul‐05 CORN/MILO 25
GC BIONOL LAKE PROVIDENCE LA NEW_PLNT CORN/MILO 108
GC BUNGE ERGON VICKSBURG VICKSBURG MS NEW_PLNT 3‐Sep‐08 CORN 60
GC LEVELLAND/HOCKLEY COUNTY ETHANOL LLC LEVELLAND TX NEW_PLNT 22‐Nov‐10 CORN 40
GC MURPHY OIL HEREFORD TX NEW_PLNT 1‐Mar‐09 CORN/MILO 115
GC SOUTH LOUISIANA ETHANOL BELLE CHASSE LA NEW_PLNT CORN 65
GC SOZO ENERGY TUCUMCARI NM 1‐Mar‐09 CORN 10
GC VERENIUM JENNINGS LA NEW_PLNT 1‐Jun‐08 SUGAR CANE 1.5
GC WHITE ENERGY HEREFORD TX NEW_PLNT 16‐Jan‐08 CORN/MILO 100
GC WHITE ENERGY PLAINVIEW TX NEW_PLNT 17‐Apr‐08 CORN 100
MC ABENGOA BIOENERGY CORP COLWICH KS 1‐Mar‐07 CORN/MILO 25
MC ABENGOA BIOENERGY CORP RAVENNA NE 1‐Jun‐02 CORN/MILO 88
MC ABENGOA BIOENERGY CORP YORK NE 1‐Jul‐05 CORN/MILO 55
MC ADM COLUMBUS NE EXPANSION 1‐Jun‐06 CORN 300
MC ADVANCED BIOENERGY FAIRMONT NE 31‐Oct‐07 CORN 100
MC AGP HASTINGS NE 1‐Feb‐99 CORN 52
MC ARKALON ENERGY LLC LIBERAL KS NEW_PLNT 1‐Dec‐07 CORN 110
MC AVENTINE RENEWABLE ENERGY AURORA NE NEW_PLNT 1‐Mar‐11 CORN 113
MC BIOFUEL ENERGY WOOD RIVER NE NEW_PLNT 1‐Jun‐08 CORN 115
MC BONANZA ENERGY LLC GARDEN CITY KS 1‐Oct‐07 CORN/MILO 55
MC BOOTHILL BIOFUELS DODGE CITY KS NEW_PLNT 1‐Sep‐08 CORN 110
MC CARGILL INC BLAIR NE 1‐Mar‐07 CORN 85
MC CHIEF ETHANOL HASTINGS NE 1‐Jan‐96 CORN 62
MC CORNHUSKER ENERGY LEXINGTON LLC LEXINGTON NE EXPANSION CORN 40 105
MC DEAN CEG BURNS FLAT OK 1‐Jan‐07 MILO 2
MC E ENERGY ADAMS LLC ADAMS NE 1‐Nov‐07 CORN 50
MC E3 BIOFUELS MEAD NE 1‐May‐07 CORN 24
MC E85 INC WAHOO NE NEW_PLNT 1‐Jul‐09 CORN 100
MC EAST KANSAS AGRI‐ENERGY LLC GARNETT KS 1‐Jun‐05 CORN 35
MC ECARUSO ETHANOL GOODLAND KS NEW_PLNT CORN 20
MC ELKHORN VALLEY ETHANOL LLC NORFOLK NE NEW_PLNT 1‐Sep‐07 CORN 40
MC ESE ALCOHOL INC LEOTI KS 1‐May‐06 CORN 1.5
MC ETHANEX ENERGY SUTHERLAND NE EXPANSION CORN 25 84
MC GATEWAY ETHANOL PRATT KS 24‐Oct‐07 CORN 55
MC GREEN PLAINS RENEWABLE ENERGY CENTRAL CITY NE 1‐Apr‐04 CORN 100
MC GREEN PLAINS RENEWABLE ENERGY ORD NE 1‐May‐07 CORN 50
MC HOLT COUNTY ETHANOL ONEILL NE NEW_PLNT CORN 100
MC HUSKER AG LLC PLAINVIEW NE 1‐Mar‐07 CORN 26.5
MC KAAPA ETHANOL LLC MINDEN NE 1‐Jul‐04 CORN 40
MC KANSAS ETHANOL LLC LYONS KS NEW_PLNT 1‐May‐08 CORN 55
MC LIFE LINE FOODS SAINT JOSEPH MO 1‐Jul‐07 CORN 30
MC MGP INGREDIENTS INC ATCHISON KS 1‐Jan‐05 CORN 9
MC MID AMERICA BIOENERGY MADRID NE 1‐Jul‐07 CORN 110
MC NEBRASKA CORN PROCESSING CAMBRIDGE NE NEW_PLNT 1‐Aug‐08 CORN 44
MC NEBRASKA ENERGY AURORA NE 1‐Jun‐06 CORN 50
MC NEDAK ETHANOL ATKINSON NE NEW_PLNT 1‐Jan‐09 CORN 44
MC NESIKA SCANDIA KS NEW_PLNT 2‐Mar‐08 CORN 10
MC PRAIRIE HORIZON AGRI ENERGY PHILLIPSBURG KS 1‐Feb‐02 CORN 40
MC REEVE AGRI‐ENERGY GARDEN CITY KS 1‐Jun‐06 CORN/MILO 12
MC SIOUXLAND ETHANOL LLC JACKSON NE 1‐May‐07 CORN 50
MC STERLING ETHANOL BRIDGEPORT NE NEW_PLNT 1‐Dec‐08 CORN 45
MC TRENTON AGRI PRODUCTS LLC TRENTON NE 1‐Dec‐06 CORN 40
MC VALERO ALBION NE 31‐Oct‐07 CORN 110
MC WESTERN PLAINS ENERGY LLC CAMPUS KS 1‐Jan‐04 CORN 45
MC WHITE ENERGY RUSSELL KS 1‐May‐06 MILO/WHEAT STARCH 48
MW ABENGOA MOUNT VERNON IN NEW_PLNT 2‐Feb‐10 CORN 100
MW ABENGOA BIOENERGY OF ILLINOIS MADISON IL NEW_PLNT 1‐Jul‐10 CORN 88
MW ACE ETHANOL LLC STANLEY WI 1‐Aug‐02 CORN 40
MW ADKINS ENERGY LLC LENA IL EXPANSION 1‐Aug‐02 CORN 45
MW ADM DECATUR IL 1‐Jun‐06 CORN 290
MW ADM PEORIA IL 1‐Jun‐06 CORN 100
MW AG ENERGY RESOURCES BENTON IL NEW_PLNT CORN 5
MW AVENTINE RENEWABLE ENERGY CANTON IL NEW_PLNT 5‐Oct‐08 CORN 37
MW AVENTINE RENEWABLE ENERGY MOUNT VERNON IN NEW_PLNT 30‐Nov‐10 CORN 110
MW AVENTINE RENEWABLE ENERGY PEKIN IL 1‐Jan‐02 CORN 160
MW BADGER STATE ETHANOL LLC MONROE WI 1‐Oct‐02 CORN 55
MW BIG RIVER RESOURCES GALVA IL NEW_PLNT 1‐May‐09 CORN 100
MW CARBON GREEN BIOENERGY WOODBURY MI 1‐Sep‐06 CORN 50
MW CARDINAL ETHANOL HARRISVILLE IN NEW_PLNT 1‐Nov‐08 CORN 100
MW CENTER ETHANOL COMPANY SAUGET IL NEW_PLNT 15‐Apr‐08 CORN 54
MW CENTRAL INDIANA ETHANOL LLC MARION IN 17‐Jul‐07 CORN 50
MW COMMONWEALTH AGRI‐ENERGY LLC HOPKINSVILLE KY 1‐Dec‐05 CORN 33
MW COSHOCTON ETHANOL COSHOCTON OH NEW_PLNT 7‐Feb‐08 CORN 60
MW DIDION MILLING CAMBRIA WI NEW_PLNT 11‐Apr‐08 CORN 50
MW GLOBAL ETHANOL/MIDWEST GRAIN PROCESSORS RIGA MI 1‐Sep‐07 CORN 57
MW GUARDIAN ENERGY LIMA OH NEW_PLNT 1‐Jun‐08 CORN 54
MW HARRISON ETHANOL CADIZ OH NEW_PLNT CORN
MW ILLINOIS RIVER ENERGY LLC ROCHELLE IL 19‐Nov‐10 CORN 115
MW INDIANA BIO‐ENERGY BLUFFTON IN NEW_PLNT 1‐Sep‐08 CORN 101
MW IROQUOIS BIO‐ENERGY COMPANY LLC RENSSELAER IN 1‐Nov‐03 CORN 40
MW LIBERTY RENEWABLE FUELS ITHACA MI NEW_PLNT CORN 110
EAI, INC. (ENERGY ANALYSTS INTERNATIONAL) EAI, INC.
BIOFUELS BUSINESS OUTLOOK 2011
BIO‐37
PROJECT TYPE
START UP
DATE
FEEDSTOCK
CURRENT
CAPACITY
(MMGPY)
PLANNED
CAPACITY
(MMGPY)

U.S. FUEL ETHANOL PRODUCTION CAPACITY (EXISTING AND UNDER CONSTRUCTION)
MILLION GALLONS PER YEAR (MMGY)
EAI RGN COMPANY
Table BIO‐1 (continued)
LOCATION
START UP
PROJECT TYPE FEEDSTOCK
DATE
CURRENT
CAPACITY
(MMGPY)
PLANNED
CAPACITY
(MMGPY)
CITY ST
MW LINCOLNLAND AGRI‐ENERGY LLC PALASTINE IL 1‐Jul‐04 CORN 48
MW LIQUID RESOURCES OF OHIO MEDINA OH 1‐Jun‐95 BEVERAGE WASTE 3
MW MARQUIS ENERGY LLC HENNEPIN IL NEW_PLNT 1‐May‐08 CORN 100
MW MARQUIS ENERGY LLC NECEDAH WI NEW_PLNT 2‐Feb‐08 CORN 50
MW MARYSVILLE ETHANOL LLC MARYSVILLE MI 1‐Oct‐07 CORN 50
MW MGP INGREDIENTS INC PEKIN IL CORN/WHEAT STARCH 78
MW NEW ENERGY CORP SOUTH BEND IN 1‐Mar‐05 CORN 102
MW ONE EARTH ENERGY GIBSON CITY IL NEW_PLNT 11‐Jun‐09 CORN 118
MW PARALLEL PRODUCTS LOUISVILLE KY 1‐Jun‐06 BEVERAGE WASTE 9
MW PATRIOT RENEWABLE FUELS LLC ANNAWAN IL NEW_PLNT 1‐Sep‐08 CORN 100
MW PLOVER ETHANOL PLOVER WI CORN 4
MW POET ALEXANDRIA IN NEW_PLNT 18‐Apr‐08 CORN 60
MW POET CARO MI 1‐Mar‐03 CORN 40
MW POET CLOVERDALE IN NEW_PLNT 1‐Jun‐08 CORN 92
MW POET FOSTORIA OH 1‐Oct‐08 CORN 60
MW POET LEIPSIC OH NEW_PLNT 10‐Jan‐08 CORN 60
MW POET MARION OH NEW_PLNT 1‐Nov‐08 CORN 60
MW POET NORTH MANCHESTER IN NEW_PLNT 11‐Sep‐08 CORN 65
MW POET PORTLAND IN 1‐Jan‐98 CORN 60
MW THE ANDERSONS ALBION MI 1‐Aug‐06 CORN 55
MW THE ANDERSONS CLYMERS IN 1‐May‐07 CORN 110
MW THE ANDERSONS GREENVILLE OH NEW_PLNT 12‐Feb‐08 CORN 110
MW UNITED ETHANOL MILTON WI 1‐Apr‐05 CORN 55
MW UNITED WI GRAIN PRODUCERS LLC FRIESLAND WI 1‐Apr‐03 CORN 55
MW UTICA ENERGY LLC OSHKOSH WI 1‐Apr‐03 CORN 52
MW VALERO BLOOMINGBURG OH NEW_PLNT 1‐Apr‐08 CORN 110
MW VALERO JEFFERSON WI 1‐Nov‐07 CORN 110
MW VALERO LINDEN IN 1‐Jul‐07 CORN 110
MW VALERO REYNOLDS IN NEW_PLNT 1‐Jan‐09 CORN 110
MW WESTERN ILLINOIS ETHANOL GRIGGSVILLE IL NEW_PLNT 1‐Jan‐09 CORN 110
MW WESTERN WISCONSIN RENEWABLE ENERGY LLC BOYCEVILLE WI 1‐Sep‐06 CORN 45
NES BIOENERGY INTERNATIONAL CLEARFIELD PA NEW_PLNT 1‐Jan‐10 CORN 110
NES COSKATA INC MADISON PA NEW_PLNT 1‐Oct‐12 CELLULOSE 0.04
NES MASCOMA CORP ROME NY NEW_PLNT 1‐Dec‐08 WOOD BYPRODUCTS 0.2
NES RIVERWRIGHT ENERGY BUFFALO NY NEW_PLNT CORN
NES SUNOCO VOLNEY NY NEW_PLNT 1‐Sep‐08 CORN 114
NES WESTERN NEW YORK ENERGY LLC SHELBY NY 1‐Nov‐07 CORN 50
NT ABSOLUTE ENERGY LLC SAINT ANSGAR IA NEW_PLNT 12‐Feb‐08 CORN 100
NT ADM CEDAR RAPIDS IA 1‐Jan‐81 CORN 420
NT ADM CLINTON IA 1‐Jun‐06 CORN 237
NT ADM MARSHALL MN 1‐Jun‐06 CORN 40
NT ADM WALLHALLA ND 1‐Jun‐06 CORN/BARLEY 28
NT AGSTAR FINANCIAL DYERSVILLE IA NEW_PLNT 4‐Sep‐08 CORN 110
NT AL‐CORN CLEAN FUEL CLAREMONT MN 1‐May‐96 CORN 35
NT ALCHEM LTD LLLP GRAFTON ND CORN 10.5
NT AMAIZING ENERGY LLC ATLANTIC IA NEW_PLNT 1‐Sep‐08 CORN 110
NT AMAIZING ENERGY LLC DENISON IA 1‐Jan‐06 CORN 40
NT BIG RIVER RESOURCES GALVA IA NEW_PLNT 1‐Jun‐09 CORN 100
NT BIG RIVER RESOURCES WEST BURLINGTON IA 2‐Apr‐04 CORN 92
NT BIOFUEL ENERGY FAIRMONT MN NEW_PLNT 19‐Jun‐08 CORN 115
NT BLUE FLINT ETHANOL UNDERWOOD ND 1‐Dec‐05 CORN 50
NT BUSHMILLS ETHANOL INC ATWATER MN 30‐Dec‐05 CORN 40
NT CARGILL INC EDDYVILLE IA 1‐Dec‐09 CORN 35 110
NT CENTRAL MN ETHANOL COOP LITTLE FALLS MN 1‐Jan‐85 CORN 21.5
NT CHIPPEWA VALLEY ETHANOL CO BENSON MN 1‐Mar‐04 CORN 45
NT CORN LP GOLDFIELD IA 1‐Nov‐94 CORN 50
NT CORN PLUS LLP WINNEBAGO MN 1‐Dec‐05 CORN 44
NT DAKOTA ETHANOL LLC WENTWORTH SD 1‐Aug‐06 CORN 48
NT DENCO LLC MORRIS MN 1‐Dec‐06 CORN 21.5
NT DEXTER ETHANOL LLC DEXTER IA NEW_PLNT 1‐Jun‐08 CORN 100
NT FIBERIGHT LLC BLAIRSTOWN IA CORN 5
NT FLINT HILLS RESOURCES FAIRBANK IA 1‐Nov‐04 CORN 115
NT FLINT HILLS RESOURCES IOWA FALLS IA 1‐Nov‐04 CORN 105
NT FLINT HILLS RESOURCES MENLO IA NEW_PLNT 18‐Aug‐10 CORN 100
NT FLINT HILLS RESOURCES SHELL ROCK IA NEW_PLNT 18‐Aug‐10 CORN 110
NT FURTHER FUELS GRAND JUNCTION IA NEW_PLNT 1‐Jun‐09 CORN 110
NT GEVO LUVERNE MN 1‐May‐06 CORN 21
NT GLACIAL LAKES ENERGY LLC MECKLING SD NEW_PLNT CORN 60
NT GLACIAL LAKES ENERGY LLC MINA SD NEW_PLNT 1‐Jul‐08 CORN 100
NT GLACIAL LAKES ENERGY LLC WATERTOWN SD 1‐Jan‐85 CORN 100
NT GLOBAL ETHANOL/MIDWEST GRAIN PROCESSORS LAKOTA IA 1‐Feb‐07 CORN 95
NT GOLDEN GRAIN ENERGY LLC MASON CITY IA 1‐Dec‐04 CORN 140
NT GRAIN PROCESSING CORP MUSCATINE IA 1‐Jun‐06 CORN 20
NT GRANITE FALLS ENERGY LLC GRANITE FALLS MN 1‐Jan‐05 CORN 52
NT GREEN PLAINS RENEWABLE ENERGY FERGUS FALLS MN NEW_PLNT 1‐Mar‐08 CORN 57.5
NT GREEN PLAINS RENEWABLE ENERGY SHENANDOAH IA 1‐Sep‐07 CORN 50
NT GREEN PLAINS RENEWABLE ENERGY SUPERIOR IA NEW_PLNT 1‐Jul‐08 CORN 50
NT GUARDIAN ENERGY JANESVILLE MN NEW_PLNT 1‐Sep‐09 CORN 110
NT HEARTLAND CORN PRODUCTS WINTHROP MN 1‐Nov‐99 CORN 100
NT HEARTLAND GRAIN FUELS LP ABERDEEN SD 1‐Apr‐08 CORN 55
NT HEARTLAND GRAIN FUELS LP HURON SD 1‐Jun‐06 CORN 30
NT HERON LAKE BIOENERGY LLC HERON LAKE MN 1‐Oct‐07 CORN 50
EAI, INC. (ENERGY ANALYSTS INTERNATIONAL) EAI, INC.
BIOFUELS BUSINESS OUTLOOK 2011
BIO‐38

U.S. FUEL ETHANOL PRODUCTION CAPACITY (EXISTING AND UNDER CONSTRUCTION)
MILLION GALLONS PER YEAR (MMGY)
EAI RGN COMPANY
Table BIO‐1 (continued)
LOCATION
CITY ST
NT HIGHWATER ETHANOL LAMBERTON MN NEW_PLNT 1‐Sep‐09 CORN 50
NT HOMELAND ENERGY SOLUTIONS NEW HAMPTON IA NEW_PLNT 1‐May‐09 CORN 100
NT LINCOLNWAY ENERGY LLC NEVADA IA 1‐Apr‐03 CORN 50
NT LITTLE SIOUX CORN PROCESSORS LP MARCUS IA 1‐Apr‐03 CORN 52
NT MINNESOTA ENERGY BUFFALO LAKE MN 1‐Jan‐95 CORN 18
NT MURPHY OIL HANKINSON ND NEW_PLNT 1‐Aug‐08 CORN 110
NT NEW GEN ENERGY MARION SD NEW_PLNT 1‐Feb‐08 CORN 100
NT NORTH COUNTRY ETHANOL LLC ROSHOLT SD 1‐Oct‐06 CORN 20
NT PENFORD PRODUCTS CEDAR RAPIDS IA NEW_PLNT 13‐May‐08 CORN 45
NT PINE LAKE CORN PROCESSORS LLC STEAMBOAT ROCK IA 1‐Mar‐05 CORN 20 30
NT PLATINUM ETHANOL LLC ARTHUR IA NEW_PLNT 1‐Sep‐08 CORN 110
NT PLYMOUTH ETHANOL MERRILL IA NEW_PLNT 1‐Jan‐09 CORN 50
NT POET ASHTON IA 1‐Jan‐02 CORN 55
NT POET BIG STONE CITY SD 1‐Jan‐97 CORN 79
NT POET BINGHAM LAKE MN 1‐Jan‐02 CORN 27.5
NT POET CHANCELLOR SD 1‐Mar‐03 CORN 110
NT POET COON RAPIDS IA 1‐May‐06 CORN 54
NT POET CORNING IA 1‐Apr‐05 CORN 60
NT POET EMMETSBURG IA 1‐Apr‐05 CORN 50
NT POET GLENVILLE MN 1‐Jun‐06 CORN 40
NT POET GOWRIE IA 1‐May‐03 CORN 60
NT POET GROTON SD 1‐Feb‐04 CORN 53
NT POET HANLONTOWN IA 1‐May‐04 CORN 45
NT POET HUDSON SD 1‐Mar‐06 CORN 56
NT POET JEWELL IA 1‐Mar‐06 CORN 60
NT POET LAKE CRYSTAL MN 1‐Jan‐00 CORN 56
NT POET MITCHELL SD 1‐Dec‐06 CORN 68
NT POET PRESTON MN 1‐Jan‐88 CORN 36
NT POET SCOTLAND SD 1‐Jul‐06 CORN 11
NT QUAD‐COUNTY CORN PROCESSORS GALVA IA 1‐Dec‐06 CORN 27
NT RED TRAIL ENERGY LLC RICHARDTON ND 1‐Oct‐06 CORN 50
NT REDFIELD ENERGY LLC REDFIELD SD 1‐Apr‐07 CORN 50
NT SIOUXLAND ENERGY & LIVESTOCK COOP SIOUX CENTER IA 1‐Dec‐07 CORN 60
NT SOUTHWEST IOWA RENEWABLE ENERGY LLC COUNCIL BLUFFS IA NEW_PLNT 1‐Jan‐09 CORN 110
NT TATE & LYLE FORT DODGE IA NEW_PLNT 1‐Mar‐09 CORN 105
NT THARALDSON ETHANOL CASSELTON ND NEW_PLNT 29‐Dec‐08 CORN 100
NT US BIOENERGY CORP GRINNELL IA NEW_PLNT 1‐Sep‐08 CORN 0
NT VALERO ALBERT CITY IA 1‐Dec‐06 CORN 110
NT VALERO AURORA SD 1‐Dec‐03 CORN 120
NT VALERO CHARLES CITY IA 1‐Apr‐07 CORN 110
NT VALERO FORT DODGE IA 1‐Jun‐07 CORN 110
NT VALERO HARTLEY IA NEW_PLNT 1‐Sep‐08 CORN 110
NT VALERO WELCOME MN NEW_PLNT 30‐Jun‐09 CORN 110
NT XETHANOL BIOFUELS LLC HOPKINTON IA 1‐Sep‐05 CORN 1.5
PNW CASCADE GRAIN CLATSKANIE OR NEW_PLNT 19‐May‐08 CORN 108
PNW NORTHWEST RENEWABLE LLC LONGVIEW WA NEW_PLNT CORN 55
PNW PACIFIC ETHANOL BOARDMAN OR 1‐Aug‐07 CORN 40
PNW SUMMIT BIOFUELS CORNELIUS OR NEW_PLNT 1‐Aug‐09 WASTE SUGARS 1
PSW CALGREN RENEWABLE FUELS PIXLEY CA NEW_PLNT 10‐Jul‐09 CORN 55
PSW CILION ETHANOL KEYES CA NEW_PLNT 1‐Jun‐08 CORN 50
PSW GOLDEN CHEESE COMPANY OF CALIFORNIA CORONA CA 1‐Jan‐85 CHEESE WHEY 5
PSW PACIFIC ETHANOL CALIPATRIA CA NEW_PLNT CORN 50
PSW PACIFIC ETHANOL MADERA CA 1‐Oct‐06 CORN 35
PSW PACIFIC ETHANOL STOCKTON CA NEW_PLNT 10‐Oct‐08 CORN 60
PSW PARALLEL PRODUCTS RANCHO CUCAMONGA CA 1‐Jun‐06 FOOD WASTE 4
PSW PHOENIX BIOFUELS GOSHEN CA 1‐Sep‐05 CORN 25
PSW PINAL ENERGY LLC MARICOPA AZ 1‐Jul‐07 CORN 55
RM AMERICAN ETHANOL BUTTE MT NEW_PLNT 11‐Aug‐08 CORN
RM FRONT RANGE ENERGY LLC WINDSOR CO 1‐May‐06 CORN 40
RM IDAHO ETHANOL PROCESSING CALDWELL ID 1‐Mar‐07 CORN/POTATOS 5
RM KL PROCESS DESIGN UPTON WY 1‐Jan‐08 WOOD WASTE 2.5
RM LIQUID MAIZE LAMAR CO NEW_PLNT CORN 15
RM MERRICK AND COMPANY GOLDEN CO 1‐Dec‐95 BREWERY WASTE 3
RM NEXSUN ENERGY WALSH CO CORN 3
RM PACIFIC ETHANOL BURLEY ID NEW_PLNT 11‐Apr‐08 CORN 60
RM RENOVA ENERGY HEYBURN ID NEW_PLNT CORN 20
RM RENOVA ENERGY TORRINGTON WY 1‐Aug‐06 CORN 12
RM STERLING ETHANOL STERLING CO 1‐Nov‐05 CORN 42
RM YUMA ETHANOL YUMA CO 1‐Jun‐07 CORN 40
SES APPOMATTOX BIO ENERGY HOPEWELL VA NEW_PLNT 1‐Jan‐11 BARLEY 55
SES CLEAN BURN FUELS RAEFORD NC NEW_PLNT 1‐Feb‐10 CORN 60
SES ETHANOL GRAIN PROCESSORS LLC OBION TN NEW_PLNT 30‐Nov‐08 CORN 115
SES FIRST UNITED ETHANOL LLC CAMILLA GA NEW_PLNT 10‐Oct‐08 CORN 100
SES RANGE FUELS SOPERTON GA NEW_PLNT 1‐Mar‐10 WASTE WOOD 10
SES TATE & LYLE LOUDON TN 1‐Jun‐06 CORN 60
SES WIND GAP FARMS BACONTON GA 1‐Jun‐06 BREWERY WASTE 0.4
*This list includes sites currently operating, existing but shutdown, under construction, and under construction but shutdown
FEEDSTOCK
CURRENT
CAPACITY
(MMGPY)
PLANNED
CAPACITY
(MMGPY)
EAI, INC. (ENERGY ANALYSTS INTERNATIONAL) EAI, INC.
BIOFUELS BUSINESS OUTLOOK 2011
BIO‐39
PROJECT TYPE
START UP
DATE

Table BIO-2
U.S. CELLULOSIC ETHANOL PROJECTS UNDER DEVELOPMENT AND CONSTRUCTION
COMPANY LOCATION TECHNOLOGY
PRODUCTION
CAPACITY MMGY
FEEDSTOCK
Abengoa York, NE 11.6 corn stover, wheat straw, milo stubble,
Hugoton, KS 11.6 switchgrass, and other biomass
AE Biofuels Butte, MT Ambient Temperature Cellulose Starch
Hydrolysis
Bluefire Corona, CA Arkenol Process Technology (Concentrated
18
Lancaster, CA Acid Hydrolysis Technology Process)
3.1
California Ethanol +
Power, LLC (ce+p)
switchgrass, grass seed, grass straw, and corn
stalks
Brawley, CA 55 local Imperial Valley grown sugarcane; facility
powered by sugarcane bagasse
Coskata Madison, PA biological fermentation technology;
proprietary microorganisms and efficient
bioreactor designs in a three‐step
conversion process that can turn most
carbon‐based feedstock into ethanol
DuPont Danisco
Cellulosic Ethanol LLC
0.04 any carbon‐based feedstock, including biomass,
municipal solid waste, bagasse, and other
agricultural waste
Vonore, TN enzymatic hydrolysis technology 0.25 switchgrass, corn stover, corn fiber, and corn cobs
Econfin, LLC Washington Count Solid state fermentation process developed
by Alltech
Flambeau River Biofuels
LLC
Park Falls, WI Thermo‐chemical conversion of biomass
using advanced gasification technologies
followed by Fisher‐Tropsch catalytic
conversion into renewable liquid fuels and
waxes (“Thermal 1” process)
1.3 corn cobs
6 softwood chips, wood, and forest residues
ICM Inc. Shelley, ID enzyme technology 18 agricultural residues including wheat straw, barley
straw, corn stover, switchgrass, and rice straw
KL Process Upton, WY therman‐mechanical process 1.5 soft wood, waste wood, including cardboard, and
paper
Lignol
Innovations/Suncor
Mascoma/ New York
State Energy Research
and Development
Authority
Mascoma/Michigan
Economic Development
Corporation/Michigan
State University
New Plant Corp.
(formerly Stora Enso
North America)
New Plant Corp.
(formerly Alico)
Grand Junction, CO biochem‐organisolve 2.5 woody biomass, agricultural residues, hardwood,
and softwood
Rome, NY 5 lignocellulosic biomass, including switchgrass,
paper sludge, and wood chips
Chippewa County, “consolidated bioprocessing” refinery would
use genetically modified bacteria to break
down and ferment local wood chips
Wisconsin Rapids, WI 5.5 woody biomass, mill residues
Vero Beach, FL INEOS Bio Ethanol process (gasification,
fermentation and distillation)
40
8 municipal solid waste (MSW); unrecyclable paper;
Construction & Demolition debris (C&D); tree, yard
and vegetative waste; and energy crops
Pacific Ethanol Boardman, OR BioGasol 2.7 Wheat straw, stover, and poplar residuals
POET Scotland, SD BFRAC separates the corn starch from the 0.02 corn fiber, corn cobs, and corn stalks
Emmetsburg, IA corn germ and corn fiber, the cellulosic
31.25
Range Fuels Inc. Soperton, GA two‐step
i th
thermo‐chemical
t t t th
process
k l
(K2) 20 woodchips (mixed hardwood)
Verenium Jennings, LA C5 and C6 fermentations 1.4
sugarcane bagasse, specially‐bred energy cane,
Highlands County, 36
high‐fiber sugar cane
ZeaChem Boardman, OR 1.5 poplar trees, sugar, wood chips
Total (MMGY) 280.26
Total (MBPD) 18.28
For more information on these projects visit www.EthanolRFA.org.
green waste, wood waste, and other cellulosic
urban wastes (post‐sorted municipal solid waste)
EAI, INC. (ENERGY ANALYSTS INTERNATIONAL) EAI, INC.
BIOFUELS BUSINESS OUTLOOK 2011
BIO-40

BIO‐41
COLORADO FRONT RANGE LOCAL ETHANOL SUPPLY
MAJOR ETHNOL PLANTS WITHIN 400 MILES
STATE COMPANY CITY
CURRENT
CAP MMGPY
Table BIO-3
CURRENT CAP MBPD
PLANNED CAP
MMGPY
PLANNED CAP
MBPD
START UP DATE FEEDSTOCK
CO GREAT WESTERN ETHANOL EVANS 100 6.52 09/01/09 CORN
CO FRONT RANGE ENERGY LLC WINDSOR 40 2.61 05/01/06 CORN
CO MERRICK GOLDEN 3 BREWERY WASTE
CO STERLING ETHANOL STERLING 42 2.74 11/01/05 CORN
CO YUMA ETHANOL YUMA 40 2.61 06/01/07 CORN
NE PANHANDLE ETHANOL BAYARD 100 6.52 08/01/08 CELLULOSE
NE STERLING ETHANOL BRIDGEPORT 45 2.94 12/01/08 CORN
NE CENTRAL BIO ENERGY IMPERIAL 100 6.52 CORN
NE MID AMERICA BIOENERGY MADRID 110 7.18 07/01/07 CORN
NE WAUNETA ECONOMIC DEVELOPMENT WAUNETA 100 6.52 CORN
NE TRENTON AGRI PRODUCTS LLC TRENTON 40 2.61 12/01/06 CORN
KS NEXSUN ENERGY ULYSSES 40 2.61 02/01/09 CORN
KS SUNFLOWER BIOENERGY HOLCOMB 110 7.18 CORN
KS WESTERN PLAINS ENERGY LLC CAMPUS 45 2.94 CORN
NE SOUTHWEST BIOFUELS MC COOK 55 3.59 CORN
KS ABENGOA BIOENERGY CORP HUGOTON 115 7.50 CORN/CELLULOSIC
KS BONANZA ENERGY LLC GARDEN CITY 55 3.59 CORN/MILO
KS PANDA ETHANOL SUBLETTE 100 6.52 CORN
NE HI‐LINE ETHANOL MOOREFIELD 100 6.52 CORN
KS ARKALON ENERGY LLC LIBERAL 110 7.18 CORN
NE FURNAS COUNTY ETHANOL ARAPAHOE 100 6.52 CORN
NE CORNHUSKER ENERGY LEXINGTON LLC LEXINGTON 40 2.61 105 6.85 CORN
KS DIAL BIO RENEWABLE FUELS DODGE CITY 113 7.37 CORN
NE DAWSON COUNTY ETHANOL ELM CREEK 100 6.52 CORN
NE E‐ENERGY BROKEN BOW BROKEN BOW 100 6.52 CORN
NE PHELPS COUNTY ETHANOL HOLDREGE 100 6.52 CORN
KS PRAIRIE HORIZON AGRI ENERGY PHILLIPSBURG 40 2.61 02/01/02 CORN
NE MERCURY ETHANOL PROJECT ALMA 55 3.59 09/01/09 CORN
TOTAL 2092.5 136.50 4361 284.47
EAI, INC. (ENERGY ANALYSTS INTERNATIONAL) EAI, INC.
BIOFUELS BUSINESS OUTLOOK 2011

BIO‐42
COLORADO FRONT RANGE LOCAL BIODIESEL SUPPLY
MAJOR BIODIESEL PLANTS WITHIN 400 MILES DISTANCE
STATE COMPANY CITY
Table BIO-4
CURRENT CAP
MMGPY
CURRENT CAP
MBPD
PLANNED CAP
MMGPY
PLANNED CAP
MBPD
START UP
DATE
FEEDSTOCK
CO ROCKY MOUNTAIN BIODIESEL INDUSTRIES LLC BERTHOUD 3 0.20 7 0.46 05/01/08 MULTI FEEDSTOCK
WY BLUE SKY BIODIESEL CHEYENNE 5 0.33 09/01/06 SOYBEAN OIIL
NE WYOBRASKA BIODIESEL GERING 10 0.65 03/01/07 SOYBEAN OIIL
NE PONEER BIODIESEL GERING 2 0.13 04/01/06 SOYBEAN OIIL
CO AMERICAN AGRI‐DIESEL LLC BURLINGTON 6 0.39 08/01/06 SOYBEAN OIL
NE SUNRISE BIODIESEL GRANT 12 0.78 TALLOW
NE REPUBLICAN VALLEY BIOFUELS ARAPAHOE 10 0.65 09/01/08 SOYBEAN OIL
TOTAL 53.5 3.49 219.2 14.30
EAI, INC. (ENERGY ANALYSTS INTERNATIONAL) EAI, INC.
BIOFUELS BUSINESS OUTLOOK 2011

REG
PRODUCT REGULATIONS
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DENVER NFR FUEL SUPPLY COSTS – IMPACTS 2011

INTRODUCTION
PRODUCT REGULATIONS
Fuel products in Colorado are regulated to ensure product consistency, attainment of performance
standards, insurance that public safety considerations are met, as well as to minimize
environmental impacts resulting from the production and transportation of and the use of motor
vehicle fuels. In the United States, it is the U.S. EPA that in many cases determines fuel properties
that are necessary to meet national priorities concerning the environment. On a more local level, it
is the lead planning agencies such as the Regional Air Quality Council (RAQC) and the Colorado
Department of Public Health and Environment (CDPHE) that propose fuels strategies and programs
considered and adopted by the Colorado Air Quality Commission.
In this section, product regulations that impact gasoline specifications are reviewed with emphasis
on those facets that may impact Colorado’s decision process in selecting a gasoline formation for
its SIP program for reducing ozone pollution. Topics included in this review are; background on
ozone pollution, gasoline specification grades instituted to reduce ozone pollution, major
regulations to reduce gasoline benzene levels but also impact gasoline RVP levels and prospective
legislation impacting refiners.
OZONE POLLUTION
Gasoline in the Denver North Front Range (DNFR) area is regulated to reduce summertime fuel
volatility as a result of this area’s violation of the federal National Ambient Air Quality Standards for
ozone. As a result of this noncompliance, the U.S. EPA requires that summertime gasoline
distributed and used in the Denver North Front Range’s eight‐hour ozone nonattainment area be
limited to a maximum volatility of 7.8 pounds p.s.i., as measured by the Reid Vapor Pressure (RVP)
test.
Reduction in summertime fuel volatility results in a reduction of hydrocarbon evaporative
emissions that is one of the principle precursors in the formation of tropospheric ozone. Ground‐
level ozone pollution (sometimes called “smog”) is formed by the reaction of volatile organic
compounds (VOC) and nitrogen oxides (NOX) in the atmosphere in the presence of sunlight. These
two pollutants, often referred to as ozone precursors, are emitted by many types of pollution
sources, including on‐road and off‐road motor vehicles and engines, power plants and industrial
facilities.
In 1979, EPA promulgated the 0.12 ppm, 1‐hour ozone standard, as part of attainment of National
Ambient Air Quality Standards (NAAQS) under the Clean Air Act (CAA). Colorado violated this
standard throughout most of the 1980s, with the Denver metro area being designated a 7.8 lb. RVP
(with 1 psi waiver for ethanol blending) gasoline area as a result. However, due to the
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demonstrations via review of air monitoring data, the area was granted a series of waivers from
this requirement.
On July 18, 1997, EPA promulgated a revised standard of 0.08 ppm, measured over a longer 8‐hour
period (i.e., the 8‐hour standard) to meet requirements of 1990 amendments to CAA. The longer
period was thought to represent a more realistic exposure environment, though with a reduced
average concentration limit. In general, the 8‐hour standard was more protective of public health
and more stringent than the 1‐hour standard. Nationally there were many more areas that did not
meet the 8‐hour standard than there were areas that did not meet the shorter peak 1‐hour
standard. This included the Denver North Front Range areas. As a result of Colorado’s adoption of
its eight‐hour ozone attainment State Implementation Plan (SIP), the 7.8 lb. low RVP summertime
gasoline standard was re‐imposed on the Denver area and the overall area was expanded into the
North Front Range counties of Larimer and Weld.
On March 12, 2008, EPA significantly strengthened its national ambient air quality standards
(NAAQS) for ground‐level ozone by revising the 8‐hour “primary” ozone standard, to a level of
0.075 ppm. EPA also strengthened the secondary 8‐hour ozone standard to the level of 0.075 ppm
making it identical to the revised primary standard. Currently, Colorado is in violation of this
standard.
In September 2009, Administrator Jackson announced that EPA would reconsider the 0.075 ppm
ozone standards, set in March 2008. This resulted in the EPA announcing on January 7, 2010, that
it was considering a new “primary” standard of between 0.060 and 0.070 ppm. As with the older
0.08 ppm standard, this standard was to be measured over eight hours. EPA also stated that it
would be considering a separate “secondary” standard, a seasonal standard designed to protect
plants and trees from damage occurring from repeated ozone exposure, which can reduce tree
growth, damage leaves, and increase susceptibility to disease.
EPA conducted a review of the science that guided the 2008 decision, including more than 1,700
scientific studies and public comments from the 2008 rulemaking process. EPA also reviewed the
findings of the independent Clean Air Scientific Advisory Committee, which recommended
standards in the ranges proposed in this announcement.
EPA plans to work with states to accelerate the implementation of the new standards. The first step
is designating areas as meeting or not meeting the standards, which can be resource‐intensive.
There are 365 counties/metro areas that exceed the existing 0.075 ppm cutoff in the three year
average (2006‐2008).
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Figure REG‐1 shows the 672 counties that violated the primary and secondary ozone threshold over
a three‐year average, 2006‐2008. The blue counties are in the 0.061 to 0.075 ppm range and could
be in violation under any new proposed rule. The green counties are expected to be in attainment
with any possible ozone standard within the concentration band EPA is considering, having current
monitored eight‐hour ozone values below 0.060 ppm. Colorado and the North Front Range is one
of the areas in violation of the current 0.075 ppm eight‐hour ozone standards. To reduce the
workload for states during the interim period of reconsideration, the agency will propose to stay
the 2008 standards for the purpose of attainment and nonattainment area designations. The stay
will allow states and EPA to prepare for an accelerated ozone designation process for the
reconsidered standards to be completed by late 2011.
Currently EPA is in the process of finalizing its new ozone standards and coming up with a new
timing and accelerated process for designations and filing of State Implementation Plans. In
general, it is expected that State Implementation Plans will have to be filed with EPA in 2013.
Figure REG‐1
EPA Ozone Non-Attainment Areas
Orange counties are non attainment under current rules. Blue counties will be in violation under new rules.
Green counties are below .060 ppm and safe under new rules.
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Copyright ©: EAI, Inc., 2011
EPA will continue to require permitting of new and modified air pollution sources under the
Prevention of Significant Deterioration (PSD) program for the 2008 ozone standards. In addition,
EPA and states will continue to implement the 1997 ozone standards. The reconsideration affects

oth the “primary” and “secondary” ozone standards.
EPA’s 8‐hour ozone rule addresses the following:
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• Classification of Areas
• Attainment Deadlines
• Transition from 1‐hour to 8‐hour NAAQS
• Mandatory Control Measures
• Consequences of Failure To Attain Standard
• Interstate Transport of Ozone
• Modeling and Attainment Demonstration
• Reasonable Further Progress Reporting
• Reasonably Available Control Measure/Technology (RACM/RACT)
• Conformity (Transportation)
• New Source Review
The SIP Process
States use the SIP process to identify the emissions sources that contribute to the nonattainment
problem in a particular area, and to select the emissions reductions measures most appropriate for
that area, considering costs and a variety of local factors. Under the CAA, SIPs must ensure that
areas reach attainment as expeditiously as practicable. However, other programs, such as Federal
controls, also provide reductions, and States may rely on those reductions when developing their
attainment plans.
Classification of Areas (based on the severity of exceeding) and attainment deadlines
• Marginal – 3 years
• Moderate – 6 years
• Serious – 9 years
• Severe – 15 years
• Extreme – 17 years
Classification determines the minimum control measures to be included in a SIP and the maximum
time period allowed to meet the standard.
GASOLINE REGULATIONS
OVERVIEW OF FEDERAL REGULATIONS
Under the 1990 amendment to the Clean Air Act (CAA), Congress mandated reductions in
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PRODUCT REGULATIONS
emissions of ozone forming volatile organic compounds (VOC) and emissions of toxic air pollutants
through the reformulation of gasoline (RFG) to be sold in the nine largest metropolitan areas with
the most severe summertime ozone levels as well as areas that were reclassified as severe. The
original mandatory RFG areas are Los Angeles, San Diego, Hartford, New York City, Philadelphia,
Baltimore, Houston, Chicago, Milwaukee, Sacramento, CA and San Joaquin Valley, CA. In addition
to the mandatory areas, RFG must also be sold in ozone non‐attainment areas that opted into the
program. Opt‐in areas include part or all of the states of California, Connecticut, Delaware,
Washington, DC, Louisville and Covington, KY, Maryland, Massachusetts, St. Louis, MO, East St.
Louis, IL, Portsmouth‐Dover‐Rochester‐Manchester, NH, New Jersey, Rhode Island, Dallas, TX, and
Richmond‐Norfolk‐Arlington, VA. The state of California requires a California specific version of
RFG (CARB gasoline). Phoenix AZ has opted into a special version of RFG, Arizona Cleaner Burning
Gasoline. An overview of the mandated and opt‐in RFG areas is shown in Figure REG‐2.
Figure REG‐2
Mandated Reformulated Gasoline Market Areas
California
CARB RFG
RFG_STATUS_08
RFG OR CARB
Tucson
AZ CBG
Las Vegas
NV -CBG
Phoenix
AZ-CBG
Dallas
RFG
Milwaukee Racine
RFG Chicago
St. Louis
RFG
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Houston
RFG
REG‐5
RFG
New York City area
RFG
Baltimore MSA
RFG
Richmond, Norfolk
RFG
Philadelphia
RFG
Copyright ©: EAI, Inc., 2011
After the passage of CAA amendments, EPA entered into negotiations with interested parties
(states and municipal jurisdictions) to develop specific plans for implementing the RFG program.
These parties developed plans that meet the requirements of the CAA amendments as well as
address air quality issues pertaining to that area. To meet the 2.0% by weight oxygen requirement
for RFG, suppliers primarily blended either MTBE and ethanol. Prior to 2004, MTBE was used as the
oxygenate blendstock for most RFG outside of the Midwest. The Midwest, with significant local
ethanol production, was the area where ethanol was mostly used as the RFG oxygenate blendstock.
Continuing problems with leakage of MTBE into groundwater prompted a movement by a number

PRODUCT REGULATIONS
of states with mandated RFG areas to ban MTBE which effectively mandated the use of ethanol in
RFG in those areas. In 2004, several states including California, Arizona, New York and Connecticut
switched over to ethanol as a gasoline additive in place of MTBE. By 2006, 29 of the 50 states plus
the District of Columbia has either banned MTBE or capped its allowable concentration at a very
low level.
In general, reformulated gasoline has the most stringent specifications, requires the highest level of
investment for refiners and is the most expensive gasoline in the marketplace. Other areas,
including Colorado, with ozone violations initiated efforts via the SIP process to reduce
summertime gasoline emissions of ozone precursors by reducing the Reid Vapor Pressure of
gasoline sold in target market areas rather than opting in to the RFG program. An overview of the
environmental grades of gasoline sold by market area is shown in Figure REG‐3. As shown, outside
of RFG and CARB gasoline, the next most prevalent gasoline formulation is 7.8 psi RVP gasoline
followed by 7.0 psi RVP. Colorado Denver – North Front Range initiated a program in the early
2000’s to voluntarily require first 8.5 psi summertime gasoline through Memorandums Of
Understandings (MOUs) with industry, followed by initiation of the current EPA mandatory
required 7.8 psi summertime gasoline in 2004.
EAI_US_MKTDYS_2010 by BLENDS
CARFG (5)
CBG (1)
CNV 7.0 (1)
CNV 7.0 ETH 7.0 (1)
CNV 7.8 ETH 7.8 (8)
ETH 7.0 (2)
ETH 7.8 (10)
LS ETH 7.0 (1)
RFG (12)
RFG ETH 7.8 (1)
Figure REG‐3
Gasoline Environmental Grades By Market Area
PORTLAND_OR
EUREKAREDDING RENO
SACRAMENTO
MODESTO
FRESNO_BAKERSFIELD
COASTAL_CA
BISHOP
NW_LA
LA_PRM
E_LA
W_SD E_SD
SLC
PHOENIX
DENVER
EL PASO
DALLAS
AUSTIN
SAN ANTONIOHOUSTON
CORPUS CHRISTI
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MILWAUKEE
DES PLAINS
KANSAS CITY ST. LOUIS EAST
MEMPHIS
NEW ORLEANS
NASHVILLE
DETROIT
DAYTON
CINCINNATI
ATLANTA
BIRMINGHAM
BALTIMORE
GREENSBORO
CHARLOTTE
JACKSONVILLE
TAMPA
MIAMI
NEW HAVEN
NYC_LONG_ISLAN
NEWARK
PHILADELPHIA
RICHMOND
PORTLAND_ME
BOSTON
Copyright ©: EAI, Inc., 2011
As noted elsewhere, Texas Panhandle refineries supplying Colorado Front Range also supply the
Phoenix CBG and Dallas RFG areas via pipeline. The COP Borger refinery and the Frontier El

PRODUCT REGULATIONS
Dorado refinery, which supply the Colorado Front Range, also supply the Kansas City 7.0 psi RVP
area via pipelines.
EPA requires lower levels of sulfur in gasoline to ensure effectiveness of low emission control
technologies and reduce harmful air pollution. Since the beginning of 2004, the nation’s refiners
and importers of gasoline had the flexibility to manufacture gasoline such that annual average
sulfur levels are 120 ppm with a maximum cap of 300 ppm. In 2005, this refinery average was
reduced to 30 ppm, corporate average to 90 ppm and a cap of 300 ppm. Finally, by 2006, refineries
had to meet a 30‐ppm average with a cap of 90 ppm.
Gasoline produced in parts of the Western U.S. (mostly the Rockies) was allowed to meet a 150‐
ppm average and 300 ppm cap through 2006, but had to meet nationwide standards by 2007.
Small refiners with less than 1500 employees with a total corporate wide crude processing capacity
not exceeding 155 MBPD could abide by less stringent standards through 2007 when they had to
meet the final U.S. standards. If necessary, small refiners that demonstrated unusual economic
hardships could obtain an additional two years extension to meet U.S. standards. Now and in
future all refiners and importers have to meet corporate average sulfur of 30 ppm and a cap of 80
ppm.
MOBILE SOURCES AIR TOXICS (MSAT)
INTRODUCTION
Air toxics are air pollutants that cause adverse health effects. As such they are strictly regulated. To
date, the EPA has focused most of its air toxics efforts on the control of carcinogens, which are
compounds that cause cancer. Motor vehicles emit several pollutants that EPA classifies as known
or probable human carcinogens. Benzene, for instance, is a known human carcinogen, while
formaldehyde, acetaldehyde, 1.3‐butadiene and diesel particulate matter are probable human
carcinogens.
EPA estimates that mobile (car, truck, and bus) sources of air toxics account for a large share of all
cancers attributed to outdoor sources of air toxics. Some toxic compounds are present in gasoline
and are emitted to the air when gasoline evaporates or passes through the engine as unburned
fuel. Benzene, for example, is a component of gasoline. Cars emit small quantities of benzene in
unburned fuel, or as vapor when gasoline evaporates. A significant amount of automotive benzene
comes from the incomplete combustion of compounds in gasoline such as toluene and xylene that
are chemically very similar to benzene. Like benzene itself, these compounds occur naturally in
petroleum and become more concentrated when petroleum is refined to produce high octane
gasoline or when the lower boiling range, high RVP compounds are removed to reduce the overall
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RVP specification of the gasoline pool. Thus the lower the RVP specification that refiners
supplying the Colorado Front Range are required to meet, the higher the probability that certain
refiners will have difficulty in producing a benzene specification grade gasoline, assuming the
absence or limitations of other benzene removal processes.
Programs to control air toxics pollution have centered around changing fuel composition as well as
improving vehicle technology or performance. Changes in fuel composition have included lead
phase out, reduction in gasoline volatility, and reduction of benzene content in gasoline.
Improvement in vehicle technology and performance have included required periodic emission
inspections and computerized diagnostic systems that alert drivers and mechanics to
malfunctioning emission controls.
GASOLINE BENZENE REGULATIONS
The Mobile Source Air Toxics (MSAT2) final rule (72 FR 8428, February 26, 2007) contains a two‐
step approach to further reducing the benzene content of gasoline. Beginning January 1, 2011,
importers and most refineries are required to import or produce gasoline containing no more than
0.62 vol% benzene on an annual average basis. This average 0.62 vol% benzene standard can be
met by using credits. In addition to these requirements, beginning July 1, 2012, importers and most
refineries are also required to import or produce gasoline with a cap or maximum annual average
gasoline benzene content of no more than 1.3 vol%. Credits may not be used to meet the 1.3 vol%
standard.
The MSAT2 rule includes provisions for refiners and importers to generate gasoline benzene
credits. Refiners may generate early benzene credits from June 1, 2007 through December 31, 2010
if a refinery’s annual average gasoline benzene is at least 10% less than its average benzene from
January 1, 2004 through December 31, 2005, and the refinery reduces their benzene by
implementing certain technological improvements specified in the regulations. Refiners and
importers may generate standard benzene credits beginning in 2011 if a refinery’s or importer’s
annual average gasoline benzene is less than 0.62 vol%. Early benzene credits may be used to
comply with the 0.62 vol% standard during the 2011, 2012 and 2013 averaging periods, while
standard benzene credits may be used to comply with the 0.62 vol% standard within five years
from the year they were generated. For both early credits and standard credits, one credit is
equivalent to one gallon of benzene removed from gasoline. Gasoline benzene credits may be
transferred nationwide.
SMALL REFINER FLEXIBILITIES
Additional compliance flexibilities are provided for small refiners in the gasoline benzene
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regulations. The criteria for qualification as a gasoline benzene small refiner are similar to those
under the Gasoline Sulfur and Diesel Sulfur rules. To qualify as “small”, a refiner must: 1) produce
gasoline by processing crude oil through refinery processing units from January 1, 2005 through
December 31, 2005; 2) employ no more than 1,500 people company‐wide, based on the average
number of employees for all pay periods from January 1, 2005 through December 31, 2005; and, 3)
have a corporate crude oil capacity less than or equal to 155,000 BPD for 2005.
Small refiners are allowed an additional four years to comply with each benzene standard. They
must begin complying with the 0.62 vol% standard no later than January 1, 2015, and begin
complying with the 1.3 vol% standard no later than July 1, 2016. For the primary refineries
supplying the Colorado Front Range, Frontier (Cheyenne and El Dorado) is classified as a small
refiner for purposes of the MSAT rule, while ConocoPhillips Borger, Valero McKee, Sinclair Rawlins
and Suncor Denver are not. Suncor Denver refinery is in the process of installing equipment to
meet the interim benzene specification.
In addition to allowing refiners and importers to use credits to meet the 0.62 vol% annual average
standard, the gasoline benzene regulations also allow refiners and importers to carry forward a
benzene deficit from one year to the next year. If a refinery or importer exceeds the 0.62 vol%
annual average standard and does not procure sufficient credits to meet the standard, they may
offset the deficit during the following year by reducing their benzene concentration below 0.62
vol%, and/or procuring credits. Benzene deficits for one year must be offset during the following
year, and may not be carried over for a second consecutive year.
BENZENE PRE‐COMPLIANCE REPORTING REQUIREMENTS
The gasoline benzene regulations require refiners to submit annual pre‐compliance reports for
each of their refineries to EPA. The first pre‐compliance report was due by June 1, 2008 and
subsequent reports are due annually through 2010. The pre‐compliance reports must contain the
following information:
1. Any changes in the refiner's basic company or facility information since registration.
2. Estimates of the average daily volume of gasoline produced at each refinery. The volume
estimates must include gasoline produced during the periods of June 1, 2007 through
December 31, 2007, and calendar years 2008 through 2015.
3. An estimate of the average gasoline benzene concentration for the periods above.
4. For refineries expecting to participate in the benzene credit program, estimates of the
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number of credits generated and/or used during the periods above.
5. Information on project schedule by known or projected completion date (by quarter) for
each stage of the project (strategic planning, front‐end engineering, detailed engineering
and permitting, procurement and construction, and commissioning and startup).
6. Basic information regarding the selected technology pathway for compliance (e.g. re‐
routing of benzene precursors or other technologies, revamp versus grassroots, etc.).
7. Whether capital investments have been made or are projected to be made.
8. An update of the progress in each of these areas. The pre‐compliance reporting
requirements do not apply to certain types of gasoline, including imported gasoline,
gasoline produced for and used in California, gasoline produced by small refiners, gasoline
exported for use outside the United States, and gasoline produced through distillation of
transmix. These products are not included in this summary and analysis.
BENZENE PRE‐COMPLIANCE REPORTS
EPA received benzene pre‐compliance reports for 110 refineries in 2009. The 2009 benzene
pre‐compliance reports showed that:
1. Refiners are planning to comply with the benzene standards on time by installing new
benzene removal equipment at many of their refineries and using the averaging,
banking and trading provisions in the regulations to comply at the rest
2. 63 refineries are planning to install equipment to reduce gasoline benzene
3. 47 refineries are not planning to install equipment to reduce gasoline benzene because
they already comply with the gasoline benzene standards, or are planning to use credits
for compliance
4. 25 refineries are planning to generate early credits from 2007 through 2010, and 41
refineries are planning to generate standard credits beginning in 2011
5. Overall average reported benzene levels are expected to decrease from 1.05 volume
percent (vol%) in 2007 to 0.60 vol% in 2015
This data represents estimates made by refiners whose final actual compliance plans may
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change prior to January 1, 2011. While the reported information is preliminary, the results
provide a snapshot of refiners’ aggregate benzene compliance plans as of June, 2009. They
represent the assessment of those who have first‐hand knowledge of the unique situation
faced by each refinery. EPA expects that 2010 benzene pre‐compliance reports will contain
more definite information on refiners’ plans to produce gasoline which meets the benzene
standards beginning January 1, 2011.
AMERICAN RECOVERY AND REINVESTMENT ACT OF 2009
ECONOMIC STIMULUS PLAN
The economic stimulus plan passed in February 2009 has several energy related incentives. These
include:
Extension for three years the tax credit for producing electricity from wind, biomass,
geothermal or solar, solid waste, and qualified hydropower facilities. Extends such credit
for two years for marine and hydrokinetic renewable energy resources.
Allows an election in 2009 and 2010 to treat certain renewable resource facilities (e.g.,
wind, biomass, hydropower, etc.) as energy property eligible for the 30% energy tax credit.
Increases Allocations of New Clean Renewable Energy Bonds and Qualified Energy
Conservation Bonds.
Increases the national limitation on the issuance of new clean renewable energy bonds and
qualified energy conservation bonds.
Modifies the $10 per metric ton tax credit for carbon dioxide sequestration to require the
taxpayer to dispose of the carbon dioxide in secure geological storage.
GREENHOUSE GAS (GHG) EMISSIONS
The federal government is now in the process of regulating greenhouse gas (GHG) emissions. GHG
gases include Methane, Nitrous Oxide, Hydro‐fluorocarbons and Carbon‐dioxide (CO2). Carbon‐
dioxide constitutes over 80% of these emissions. Consideration of regulating greenhouse gas
emissions will involve both petroleum products themselves and refining operations.
In a U.S. Supreme Court decision in Massachusetts versus EPA, the Supreme Court ruled that the
Clean Air act (CAA) authorizes regulation of GHG’s because they meet the definition of air pollutant
under the act. The EPA published a Notice of Proposed Rulemaking on July 11, 2008 that reviews
the various CAA provisions that may be applicable to regulate GHG’s, issues raised by such
regulation, potential regulatory approaches and technologies for reducing GHG emission and
possible legislation.
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On December 12, 2009 EPA announced that GHGs threaten public health and the environment. The
findings do not in and of themselves impose any emission restrictions but rather allows EPA to
finalize the GHG standards proposed earlier in 2009 for light duty vehicles. Legislatively, the EPA is
working with the Congress and Senate on a cap and trade program that would restrict and set
targets for GHG emissions in the future. It is not certain if this proposed legislation will pass both
houses of congress, but the fact that it is being discussed, shows the coming importance of this
topic. Greater details of the proposed legislation that has passed the House and waiting possible
Senate action is provided below.
AMERICAN CLEAN ENERGY AND SECURITY ACT OF 2009
INTRODUCTION
H.R. 2454 was passed in the House in June 2009 and is currently waiting for Senate action,
expected later in 2010. H.R. 2454 would make a number of changes in energy and environmental
policies largely aimed at reducing emissions of gases that contribute to global warming. The bill
would limit or cap the quantity of certain greenhouse gases (GHGs) emitted from facilities that
generate electricity and from other industrial activities such as an oil refinery, over the 2012‐2050
period. The EPA would establish two separate regulatory initiatives known as cap‐and‐trade
programs—one covering emissions of most types of GHGs and one covering hydrofluorocarbons
(HFCs).
CAP AND TRADE PROGRAM
GHG emission control under this bill is designed to be achieved using a cap and trade program. A
cap‐and‐trade program is a regulatory policy aimed at controlling pollution emissions from specific
sources. The legislation would set a limit on total emissions for each year and would require
regulated entities to hold rights, or allowances, to the emissions permitted under that cap. Each
allowance would entitle companies to emit the equivalent of one metric ton of carbon dioxide
equivalent (mtCO2e). After the allowances for a given period were distributed, entities would be
free to buy and sell allowances.
Congressional Budget Office (CBO) estimates that about 7,400 facilities would be affected by the
cap‐and‐trade programs established by the bill. Beginning in 2012, all electricity generators would
be required to submit allowances for all GHG emissions from their sites, with the exception of
emissions from the combustion of liquid fuels, coke, and renewable biomass. Also beginning in
2012, any facility or entity that produces or imports petroleum or coal‐based liquids, petroleum
coke, or natural gas liquids would be required to submit allowances for the GHG emissions that
would result from the combustion of those fuels, if combustion of the fuel resulted in the emission
of more than 25,000 mtCO2e per year. All facilities or entities that produce or import GHGs for
direct use would be required to submit allowances for the emissions that would result when those
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gases were released into the atmosphere.
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The program would allocate to covered entities 4,627 million mtCO2e allowances in 2012—about
97 percent of the amount of such emissions by covered entities in 2005. The number of allowances
would increase to as high as 5,482 million mtCO2e in 2016 to account for certain covered entities
that would not begin compliance until that time, and then decline by 100 million to 150 million
mtCO2e (2% to 3%) per year—falling to 1,035 million mtCO2e in 2050, about 14 percent of
projected emissions from covered entities in the absence of regulation of such emissions.
CBO estimates that, in 2015, a price on emissions of CO2 that raised the average price of end‐use
energy produced from fossil fuels by 10 percent would induce about a 5 percent reduction in such
emissions. Newly enacted carbon tax in British Columbia is estimated to have added about 12
cents per gallon to gasoline price. Since new MPG rules are expected to increase fuel efficiency of
cars by 5% a year through 2020, net increase in consumer’s cost of gasoline usage is expected to be
marginal.
SUMMARY
The U.S. EPA regulates a number of fuel properties for environmental or public health reasons.
With the passage of the Clean Air Act amendments of 1990, a number of new gasoline fuel quality
programs were adopted. Wintertime carbon monoxide emissions were addressed through the
oxygenated gasoline requirement. Summertime ozone concentrations were addressed through
lower volatility gasoline standards and the reformulated gasoline program. Air toxic reduction
programs have been implement has part of the Mobile Source’s Air Toxics Rule, as well as part of
the reformulated gasoline program.
In Colorado, the Denver North Front Range is required to use lower volatility gasoline as part of the
original violation of the 1.20 ppm one‐hour ozone standard, as well as the continuing violation of
the 0.8 ppm (0.085 ppm effective) eight‐hour ozone standard, as well as the current 0.075 ppm
current eight‐hour ozone standard. It is thought that this area is quite likely to violate any expected
ozone standard that is being considered (principally eight‐hour ozone values of between 0.060 and
0.070 ppm). Additionally other areas of Colorado, such as Colorado Springs, Grand Junction, and
the four corners area, are at risk of exceeding any ozone standard within this range.
Fuel quality standards have in the past assisted Colorado in reducing mobile source emissions from
cars and trucks. These standards in combination with vehicle technology improvements plus
changes in driving patterns, can be expected to further reduce mobile source emissions. There is
the potential these standards will get tighter in the future, based on ambient air quality needs.
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GLOSSARY OF TERMS
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TERMS AND DEFINITIONS
GLOSSARY
Alkylation – Refinery process for combining light hydrocarbon olefins to produce alkylate, a
high octane gasoline blendstock
Barrel – 42 U.S. gallons
BPD – Barrels per day, volumetric rate
Blending – Refinery process where petroleum blend stocks of differing octane levels and vapor
pressures are combined in order to produce finished product gasoline.
C5 – Pentanes, see below
CBI – Caribbean Basin Initiative countries – Certain Caribbean nations that have been
authorized to distill wet ethanol feedstocks and produce dry fuel ethanol for import into the U.S.
without duty.
CBOB – Conventional gasoline blendstock for blending with ethanol
CBG – Arizona Cleaner Burning Gasoline
Coking – Refinery process to thermally crack large molecule petroleum vacuum resid into
smaller molecule, lighter petroleum liquids.
Colorado Front Range – Generally the area east of the continental divide. Contains most of the
population and refined product demand. Major metropolitan areas – Denver, Boulder, Colorado
Springs, Castle Rock, Fort Collins, Greeley
CPG – Cents per gallon
Denver NFR and DNFR – Colorado ozone non-attainment area includes Adams, Arapahoe,
Boulder, Broomfield, Denver, Douglas, Jefferson, Larimer and Weld counties.
De-pentanizer – Refinery processing unit designed to remove pentane from naphtha streams.
Light Ends – Low temperature boiling fractions of petroleum hydrocarbons. Generally refers to
the low density (light) hydrocarbons butanes and pentanes which have high volatility, i.e. high
vapor pressure.
LRVP – Low RVP, gasoline with lower RVP than standard conventional gasoline for a given
season and locale.
MBPD – 1000’s of barrels per day, volumetric rate
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NAA – Non attainment area
NFR – North Front Range
GLOSSARY
Octane – Standard measure of gasoline ability to burn in a standard spark ignition engine without
producing engine “knocking” or harmful vibration. Iso-octane molecule rated as 100 octane.
Standard automobile engines require gasoline of a minimum octane rating to perform without
knocking.
Olefins – Generally small hydrocarbon molecules with at least one double bond between
adjacent carbon atoms. In refinery processing, most olefins are produced in cracking processes
(fluid catalytic cracking and coking). Light olefins are more unstable and generally will
polymerize or react with other molecules producing off-specification products over time.
Minimum specifications are set for olefins in gasoline.
Pentanes – Five carbon straight chain hydrocarbons found in crude oil, natural liquid condensate
and produced by refinery operations. A high RVP liquid hydrocarbon.
Polymerization – Refinery process for combining light hydrocarbon olefins to produce higher
octane naphtha blendstock for gasoline blending – gives lower yields than alklyation
Psi – pounds per square inch, measurement of pressure, especially gaseous pressure. Standard
unit of measure of Reid Vapor Pressure (RVP).
RBOB – Reformulated gasoline blend-stock for blending with ethanol
Reforming – Refinery process for increasing petroleum naphtha octane levels by catalytically
reforming straight chain molecules into branched chain and ring compounds
Resid – Generally, the highest boiling portion of crude oil (boiling above 1000 degrees
Fahrenheit) – used either for asphalt cement, road oils, residual fuel oils or coker feedstocks.
Referred to as bottom of the barrel or bottoms.
RFG – Reformulated Gasoline
RFS – Renewable Fuels Standard, generally a percentage of the motor fuels marketed by a
company that must be a set amount of renewable fuel. Set annually by the EPA as directed by
EISA, or previously EPACT.
RINS – Renewable Identification Numbers – Assigned to batches of renewable fuel blendstocks
at the time of transfer from producers or importers to other participants in the fuel supply
business.
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DENVER NFR FUEL SUPPLY COSTS - IMPACTS 2011
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GLOSSARY
RVP – Reid Vapor Pressure, standard measure of the vapor pressure of gasoline, important
property in gasoline volatility. Maximum volatility of gasoline is seasonally regulated to reduce
engine operation problems and reduce emissions.
Western Slope Colorado – Generally the area west of the continental divide. Major metropolitan
area – Grand Junction
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