20111202-5190 FERC PDF (Unofficial) 12/2/2011 4:46:13 PM
STATEMENTH
OTHER FACTORS AFFECTING THE COMPETITIVENESS OF THE MARKETS SERVED BY THE REVERSED SEAWAY PIPELINE 20111202-5190 FERC PDF (Unofficial) 12/2/2011 4:46:13 PM
TABLE OF CONTENTS FOR STATEMENT H
Section
I. Introduction ...... 1
II. The U.S. Department of Justice's Analysis of the U.S. Crude Oil Pipeline Industry ...... 2
Ill. The Reversed Seaway Pipeline Is a New Entrant Pipeline ...... 3
IV. The Availability of Unutilized Capacity Held By the Reversed Seaway Pipeline's Competitors ...... 5
V. Crude Oil Exchanges and Trading ...... :: ...... 6
VI. The Reversed Seaway Pipeline's Potential Shippers are Experienced and Knowledgeable Oil Industry Participants .... ~ ...... 7
/ "-·
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c STATEMENTH OTHER FACTORS AFFECTING THE COMPETITIVENESS OF THE MARKETS SERVED BY THE REVERSED SEAWAY PIPELINE
I. Introduction_.,
1 In addition to the existing competitive alternatives discussed in Statement D and
2 the potential new entrants discussed in Statement E, there are numerous other factors
3 to consider that affect the competitiveness of the Reversed Seaway Pipeline. First,
4 when the U.S. Department of Justice ("DOJ") evaluated the competitiveness of U.S.
5 crude oil pipelines, it concluded, for various reasons, that alllower-48 crude oil pipelines
6 could be safely deregulated which also implies that all these crude oil pipelines could be
7 safely allowed to change market-based rates. 1 Second, the Reversed Seaway Pipeline ( "--··· 8 is a new entrant in terms of providing a new outlet in its origin market and a new
9 supplier to its destination market. The Reversed Seaway Pipeline is expected to begin
10 operating by the second quarter of 2012, but it is not expected to reach its full 375 MBD
11 capacity until early 2013. A new entrant, such as the Reversed Seaway Pipeline,
12 provides shippers in both its origin and destination markets with an additional option
13 which, by definition, will make the Reversed Seaway Pipeline's origin and destination
14 markets more competitive. Third, there is unutilized pipeline capacity in the Reversed
15 Seaway Pipeline's origin and destination markets, and, in the Reversed Seaway
16 Pipeline's destination market, there is unutilized dock capacity that would support
17 increased waterborne deliveries of crude oil. The pro-competitive effects of this
OIL PIPELINE DEREGULATION, REPORT OF U.S. DEPARTMENT OF JUSTICE, May 1986 (hereinafter "DOJ DEREGULATION STUDY').
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1 unutilized capacity are discussed in Statements E and G, and the data underlying the
2 calculation of the amount of unutilized capacity is presented in Statement D. Fourth,
3 crude oil exchanges and other forms of crude oil trading allows potential shippers on the
4 Reversed Seaway Pipeline in both its origin and destination markets to use all of the
5 Reversed Seaway Pipeline's competitors. Fifth, all of the Reversed Seaway Pipeline's
6 potential shippers are experienced and knowledgeable oil industry participants, which
7 implies that these shippers would have knowledge of and access to all of the
8 competitive options identified here. These five pro-competitive factors are discussed in
9 more detail below. ··
II. The U.S. Department of Justice's Analysis of the U.S. Crude Oil Pipeline Industry
10 The competitiveness of the markets served by crude oil pipelines was evaluated ( ( 11 by the DOJ in the DOJ Deregulation Study. The DOJ Study's purpose was to determine
12 whether individual oil pipeline companies faced sufficient competition in all the markets
13 they served to completely deregulate these oil pipeline companies. This is a much
14 greater lessening of regulatory constraints than would occur if a pipeline were allowed to
15 charge market-based rates subject to ongoing Commission oversight. The DOJ study
16 reached the following conclusion regarding crude oil pipelines: "The Department
17 recommends that all existing crude oil pipelines [excluding the Trans Alaska Pipeline
2 18 System] be deregulated." The DOJ elaborated on the
19
2 DOJ DEREGULATION STUDY at 62. ( ( H-2 20111202-5190 FERC PDF (Unofficial) 12/2/2011 4:46:13 PM
1 reasons why it concluded that all the existing lower-48 crude oil pipelines could be
2 safely deregulated as follows:
3 The Department has not identified any crude pipeline that presents a clear 4 case for continued federal regulations. In addition, there are theoretical s considerations that tend to lessen the need for the continued federal 6 regulation of crude pipelines. Crude production and crude refining are 7 activities that feature fewer participants and larger investments than those 8 in product marketing. Thus, crude origin and destination markets are 9 more likely to exhibit characteristics that either mitigate the exercise of 10 market power or undercut the effectiveness of regulation. These 11 characteristics, which include vertical integration, bilateral exchange, and 12 bottlenecks elsewhere in the vertical supply chain, weaken the justification 13 for continued federal regulation of crude oil pipelines. 3
Ill. The Reversed Seaway Pipeline Is a New Entrant Pipeline.
14 The Reversed Seaway Pipeline is a new entrant with service expected to begin
:s during the second quarter of 2012 with a capacity of 150 MBD, and, by early 2013, its ( __ 16 capacity will be increased to 375 MBD. The fact that the Reversed Seaway Pipeline is a
17 new entrant should be a sufficient reason to grant it the authority to charge market-
18 based rates. The Reversed Seaway Pipeline's potential shippers have existing
19 alternative means of transporting crude oil from the Reversed Seaway Pipeline's origin
20 market and/or supplying crude oil to the Reversed Seaway Pipeline's destination
21 market; namely, the means of transport they are now using before the Reversed
22 Seaway Pipeline begins service potentially during the second quarter of 2012. The
23 Reversed Seaway Pipeline has to offer a more attractive option to its shippers to get
24 them to use the Reversed Seaway Pipeline instead of whatever means these shippers
25 are currently using.
3 /d. at 62-64.
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;.-- In its 1986 DOJ Deregulation Study, the DOJ concluded that a new oil pipeline, ( (~ / 2 such as the Reversed Seaway Pipeline, could be safely deregulated independent of the
3 extent of competition that existed in the market that it served.4 Granting the Reversed
4 Seaway Pipeline the authority to charge market-based rates gives it much less
5 autonomy than it would have under complete deregulation, because the Commission
6 would continue to exercise regulatory authority over the Reversed Seaway Pipeline and
7 maintain the ability to rescind market-based rates if necessary. Therefore, there is
8 much less risk involved in granting the Reversed Seaway Pipeline market-based rate
9 authority than would be involved in deregulation.
10 The DOJ further concluded that "no newly built oil pipeline be federally regulated
11 because regulation is not needed in order to prevent economically inefficient behavior
/ 12 by new oil pipelines."5 While the DOJ concluded that neither new crude oil pipelines nor ( ( \ 13 new product pipelines should be federally regulated, it concluded that the reasons for
14 not regulating new crude oil pipelines were stronger because "the regulation of new
15 crude pipelines in particular can impose significant and costly resource allocation
16 distortions."6 Therefore, the DOJ Study's conclusions would support the deregulation of
17 all the crude oil pipelines, and all new entrant oil pipelines, and, thereby, also supports
18 the FERC granting the Reversed Seaway Pipeline the authority to charge market-based
19 rates since it is both a crude oil pipeline and a new entrant pipeline.
4 /d. at 143-44. 5 /d. at 143. 6 /d. at xv.
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c·- IV. The Availability of Unutilized Capacity Held By the Reversed Seaway "- Pipeline's Competitors
1 The amount of excess (unused) capacity held by the Reversed Seaway
2 Pipeline's competitors in both its origin and destination markets is analyzed in
3 Statement G, Tables G.3 and G.7 for the Gulf Coast Destination Market and Table G.16
4 for the Cushing Origin Market. For the Houston to Lake Charles Area definition of the
5 Gulf Coast Destination Market, the excess capacity held by others is 5. 78 times the
6 estimated deliveries by the Reversed Seaway Pipeline. For the Cushing Origin Market,
7 the excess capacity held by others is 4.45 times the estimated receipts by the Reversed
8 Seaway Pipeline when the market size is measured by local crude oil production only,
9 and 1.34 times the estimated receipts by the Reversed Seaway Pipeline when the ( -- 10 market size is measured by local crude oil production plus deliveries of crude oil to the origin market from remote production areas. 7 In both its destination and origin markets, ""---- 11
12 the excess capacity held by the Reversed Seaway Pipeline's competitors is more than
13 sufficient to replace all of the Reversed Seaway Pipeline's deliveries to its destination
14 market or its receipts in its origin market.
15 Regarding the excess capacity at the Gulf Coast dock facilities, the data needed
16 to calculate the amount of calculate the amount of unutilized dock facility capacity is
17 produced in Statement Din Tables D.8 and D.9. Table H.1. below presents a
18
7 Since the Reversed Seaway Pipeline is not yet operating, its receipts are estimated to be 90% of its 375 MBD capacity which equals 337.5 MBD. See Statement G, Table G.4.
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1 calculation of unutilized crude oil dock capacity for both geographic definitions of the
2 Reversed Seaway Pipeline's Gulf Coast Destination Market. The percentage of
3 unutilized dock capacity ranges from 35.9% for the Houston to Lake Charles Area
4 definition to 53.7% for the Gulf Coast Area definition. Clearly, the Gulf Coast dock
s facilities could accept substantially larger crude oil deliveries.
Table H.1 Utilization of Crude Oil Dock Capacity in the Reversed Seaway Pipeline's Gulf Coast Destination Market
Dock Crude Oil Capacity Receipts Unutilized Percentage Available for and Dock of Dock Geographic Definition of the Crude Oil Shipments Capacity Capacity Gulf Coast Destination Market {MBD} {MBD} {MBD} Unutilized
/ / Gulf Coast Area 12,032.9 5,566.4 6,466.5 53.7% \ ( Houston to Lake Charles Area 6,000.0 3,848.9 2,151.1 35.9%
Sources: Tables D.8 and D.9.
v. Crude Oil Exchanges and Trading
6 Exchanges and ongoing crude oil trading actively make all inbound alternatives
7 competitive with the Reversed Seaway Pipeline in its destination market and all
s outbound alternatives competitive with the Reversed Seaway Pipeline in its origin
9 market. Exchange agreements, buy-sell agreements, and spot trading agreements are
10 used throughout the crude oil industry to reduce the need to physically transport crude
11 oil (i.e., to reduce transportation costs). Product exchanges, buy-sells, and spot trading
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2 approach.
3 These agreements also can be used to transfer the ownership of crude oil
4 between locations where physical movements are not possible. Even in cases where
5 both parties to an exchange have to transport the crude oil to the location specified by
6 the other party, the exchange will still be economically advantageous so long as there is
7 a net savings in transportation costs as a result of the exchange.
VI. ., The Reversed Seaway Pipeline's Potential Shippers are Experienced and Knowledgeable Oil Industry Participants
8 · The fact that an oil pipeline's shippers are experienced and knowledgeable
9 participants in the oil pipeline industry intensifies the competitiveness of the oil pipeline
( '.0 industry. The potential shippers on the Reversed Seaway Pipeline are large ""---~ 11 independent crude oil producers, integrated oil companies, and crude oil marketers.
12 These entities clearly have the knowledge and the financial capability to thwart any
13 attempt by the Reversed Seaway Pipeline to charge rates above competitive levels.
14 The market power of the buyers of the services provided by a company, such as the
15 Reversed Seaway Pipeline, is recognized in the economic literature as an important
16 factor that helps ensure that a supplier like the Reversed Seaway Pipeline could not
17 exercise market power. 8
8 For a more detailed discussion, see W.G. SHEPHERD, THE ECONOMICS OF INDUSTRIAL ORGANIZATION 337, 345 (3rd ed. 1990) and W.G. SHEPHERD, PUBLIC POLICIES TOWARD BUSINESS 239-240 (8th ed. ( 1991). "-. __ _ H-7 20111202-5190 FERC PDF (Unofficial) 12/2/2011 4:46:13 PM
STATEMENT I
TESTIMONY
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PREPARED DIRECT TESTIMONY
OF
DR. GEORGE R. SCHINK 20111202-5190 FERC PDF (Unofficial) 12/2/2011 4:46:13 PM
TABLE OF CONTENTS
Section
I. Identity and Qualifications ...... 1
II. Purpose of Testimony, Description of the Reversed Seaway Pipeline, and Summary of Conclusions ...... 3
A. Purpose of Testimony ...... 3 B. Description of the Reversed Seaway Pipeline ...... 4 C. Summary of Conclusions ...... ,...... 13
Ill. The Major Issues Addressed in Tliis Testimony ...... 14
A The Services Provided by Cr!Jde Oil Pipelines ...... 16 B. The U.S. Department of Justice's View of the Competitiveness of Crude Oil Pipelines in the Lower-48 States ...... 18 C. The Competitive Implications of the Reversed Seaway Pipeline Being a New Entrant ...... 20 ( D. Discussion of the Competitive Analyses ...... 21 . 1. Statistical and Other Competitive Analyses Performed ...... 21 2. The Competitiveness of the Reversed Seaway Pipeline's Gulf Coast Destination Market...... 27 3. The Competitiveness of the Reversed Seaway Pipeline's Cushing Origin Market ...... 29 4. Excess Capacity in the Destination and Origin Markets ...... 34 5. New Entry into the Markets Served by Reversed Seaway Pipeline ...... 36 6. Overall Conclusions Based on the Above Results ...... 36
IV. Structure and Content of The Statements Accompanying Enterprise Products' Application ...... 37
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UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION
Enterprise Product Partners L.P. ) Docket No. OR12-__-000 And Enbridge Inc. )
PREPARED DIRECT TESTIMONY OF DR. GEORGE R. SCHINK
1 I. Identity and Qualifications
2 Q. Please state your name, business address, and business title.
3 A. My name is George R. Schink. I am a Managing Director at Navigant
4 Economics, a subsidiary of Navigant Consulting, which provides economic and c:. -- 5 financial analysis of legal and business issues to law firms, corporations and
6 government agencies. My business address is 1801 K Street, NW, Suite 500,
7 Washington, D.C. 20006.
8 Q. Please state your education and professional background.
9 A. I was awarded a B.S. in Economics from the University of Wisconsin in Madison
10 in 1964, and a Ph.D. in Economics from the University of Pennsylvania in 1971.
11 have been active as an economic consultant in the energy industry for over 30
12 years. My consulting experience involves a broad range of economic analyses of
13 markets, including market structure and market dynamics, in various industries
14 including energy, utility and telecommunications. My experience also includes
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1 consulting on government policy and regulatory issues for major oil companies,
2 gas and oil pipelines, electric utilities, and gas utilities. I also have prepared
3 analyses of the demand for and supply of crude oil, refined petroleum products,
4 natural gas, and LNG within the U.S. and other countries. Further, I have
5 presented testimony before numerous regulatory bodies, courts and Congress.
6 As part of my work in energy markets, I have done an extensive amount of work
7 on oil pipeline matters related to tariff rate levels, right-of-way payments, tariff
8 design, rate cap index design and definition, and competitive analyses. I have
9 done extensive work on price cap index-type regulation, including extensive
10 study of the price cap mechanism that the Federal Energy Regulatory
11 Commission ("FERC") uses to regulate oil pipeline tariffs. I also have analyzed 12 the appropriateness of market-based rates for oil and gas pipelines, including ( ( 13 presenting testimony before the FERC in support of pipeline companies'
14 applications for market-based rates. I have performed analyses of the structure
15 and competitiveness of over 70 oil pipeline markets in proceedings before the
16 FERC for the Buckeye Pipe Line Company proceedings and for the Williams
17 Pipe Line Company proceedings. I previously prepared the market analyses, the
18 required statements, and direct testimony in support of Colonial Pipeline's,
19 Longhorn Partners Pipeline's, Explorer Pipeline's, TEPPCO's, Wolverine Pipe
20 Line's, Shell Pipe Line's, the Rocky Mountain Pipeline System's, Magellan
21 Pipeline Company, LLC's and EnterpriseTE Products Pipeline Company, LLC's
22 applications to the FERC for market-based rates for product pipelines. Further, I
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1 have prepared the analysis, statements and direct testimony to support market- c"' 2 based rate applications for crude oil pipelines that were submitted by Pacific
3 Pipeline Partners and by Mobil Pipe Line Company. In addition to the analyses
4 submitted to the Commission, I have done similar analyses for other purposes for
5 additional pipelines. As part of my work for oil pipelines, I have analyzed the cost
6 of transportation of refined products via pipelines, barges, tankers, railroads, and
7 trucks. I also have analyzed the competition among these transportation modes.
8 My recent work in the energy industry also includes analyses of the effects on
9 market concentration of mergers of electric utilities, combination gas and electric
10 utilities, gas pipelines, oil pipelines, and integrated oil companies. I also have
11 testified on the competitive structure of the telecommunications industry and on ( 12 the impact of competition on its regulation. '--. 13 II. Purpose of Testimony, Description of The Applicant Pipeline, and Summary 14 of Conclusions
15 A. Purpose of Testimony
16 Q. What is the purpose of your testimony?
17 A. The purpose of my testimony is to sponsor and summarize the information in
18 Statements A through H and to otherwise support the request of Enterprise
19 Product Partners L.P. ("Enterprise") and Enbridge, Inc. ("Enbridge") for authority
20 to file market-based rates for the Reversed Seaway Pipeline at its proposed
21 Cushing, Oklahoma origin and its proposed U.S. Gulf Coast destination
22 (including delivery points at Houston, Texas and Beaumont-Port Arthur, Texas).
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1 B. Description of the Applicant Pipeline
2 Q. Please briefly describe the pipeline system for which market-based rates are
3 being requested.
4 A. Currently, the Seaway Crude Pipeline Company ("Seaway") carries crude oil
5 from the U.S. Gulf Coast to Cushing. Seaway is jointly owned by affiliates of
6 Enterprise and ConocoPhillips, which each own a 50 percent share. Enbridge
7 recently announced that it has agreed to purchase the 50 percent share of
8 Seaway owned by ConocoPhillips. Following the purchase, Enterprise and
9 En bridge intend to reverse the flow of Seaway in order to provide service from
10 Cushing to delivery points at Houston and the Beaumont-Port Arthur, Texas
11 area. I refer to the reversed pipeline in my testimony and other statements as
12 the "Reversed Seaway Pipeline." ( (
13 The sole receipt point for the Reversed Seaway Pipeline will be in Cushing at the
14 Enterprise West Crude Oil terminal, which is connected to the entire Cushing
15 complex and can receive from and deliver to every third party terminal and
16 pipeline in the Cushing area. The Reversed Seaway Pipeline's Houston delivery
17 point will initially be the Enterprise ECHO terminal which is being constructed by
18 Enterprise. 1 The ECHO terminal will be connected to all the refineries in the
19 greater Houston area, to dock facilities in Houston and Texas City, and to several
The ECHO terminal is slated to begin operation during the latter part of the second quarter of 2012 or the early part of the third quarter of 2012. If the Reversed Seaway Pipeline begins operating before the ECHO terminal is fully operational, I understand that temporary alternatives will be available to permit deliveries to Houston while the ECHO terminal is completed. ( ( 1-4 20111202-5190 FERC PDF (Unofficial) 12/2/2011 4:46:13 PM
c 1 pipelines owned by third parties. While the expectation is that most of the crude ""· 2 oil delivered to the ECHO terminal will ultimately be delivered to refineries in the
3 greater Houston area, barges and tankers can be used to transport this crude oil
4 to refineries throughout the Gulf Coast area. In addition, Enterprise will construct
5 an extension to the Reversed Seaway Pipeline from the Enterprise ECHO
6 terminal in Houston to the Beaumont/Port Arthur area. This pipeline connection
7 will be completed by late 2013 or early 2014. Prior to completing this pipeline
8 connection, the Beaumont-Port Arthur area can be supplied from Houston by
9 barge.
10 The Reversed Seaway Pipeline will consist of 30" pipe from Cushing to Houston.
11 The Reversed Seaway Pipeline is expected to begin operating in the second
(- 12 quarter of 2012 at an initial estimated throughput capacity of 150 MBD (thousand
~ .. 13 of barrels per day). Following pump station additions and modifications,
14 expected to be completed in early 2013, the Reversed Seaway Pipeline will have
15 an estimated throughput capacity of 375 MBD. The analyses in the application
16 are performed using a 375 MBD throughput capacity for the Reversed Seaway
17 Pipeline.2
2 The 375 MBD throughput capacity for the Reversed Seaway Pipeline is its throughput capacity transporting light sweet crude oil (e.g., WTI or West Texas Intermediate). If the Reversed Seaway Pipeline were transporting heavy sour crude oil (e.g., WCS or Western Canadian Select), then its throughput capacity would be about 275 MBD. For a 50/50 batched mix ofWTI and WCS, the estimated throughput capacity would be close to 275 MBD, and it is expected that the Reversed Seaway Pipeline will transport a batched mix of light sweet and heavy sour crude oils. Nonetheless, to be conservative (i.e., to portray the largest possible market presence for the Reversed Seaway Pipeline), the analyses are done using a 375 MBD throughput capacity for the Reversed Seaway Pipeline.
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~( 1 Q. Please briefly describe the product market for the Reversed Seaway Pipeline. ( / 2 A. The Reversed Seaway Pipeline intends to transport both light sweet crude oil
3 (e.g., West Texas Intermediate or WTI) and a heavy sour Western Canadian
4 bitumen blend (e.g., Western Canadian Select or WCS); however, it will be able
5 to move any type of crude oil. The appropriate product definition therefore is all
6 crude oil.
7 Q. Please describe briefly the Reversed Seaway Pipeline's destination and origin
8 markets for which market-based rates are sought and the competition the
9 Reversed Seaway Pipeline faces in these markets.
10 A. The destination market consists of the area from Corpus Christi, Texas to Mobile,
11 Alabama (i.e. the "Gulf Coast Area" definition of the Reversed Seaway Pipeline's
12 Gulf Coast destination market). This destination market encompasses the Texas ( (
13 Gulf Coast Refining District and the Louisiana Gulf Coast Refining District, as
14 defined by the Energy Information Administration of the U.S. Department of
15 Energy, plus one county in Texas immediately to the north of this area which
16 contains the Valero refinery in Three Rivers, Texas.3 See Figure 1 below.
3 The Valero refinery in Three Rivers is linked by pipeline to the Texas Gulf Coast refining area and is an integral part of the Texas Gulf Coast refining area.
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Figure 1 The Reversed Seaway Pipeline's Gulf Coast Area Geographic Definition of the Destination Market
1 A more conservative alternative definition of the destination market supplied by
2 Reversed Seaway Pipeline is also analyzed. This conservative alternative is
3 referred to as the "Houston to Lake Charles Area," and is defined to include the
4 area from Houston, Texas to Lake Charles, Louisiana (i.e. the Houston to Lake
5 Charles Area component of the Reversed Seaway Pipeline's Gulf Coast Area
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1 destination market).4 This narrower definition of the destination market was
2 accepted by the Commission for Mobil Pipe Line Company's Pegasus crude oil
3 pipeline from Patoka, Illinois to Nederland, Texas.5 Nederland is located in the
4 Beaumont-Port Arthur area with subsequent pipeline linkages, owned by others,
5 from Nederland to Houston and to Lake Charles.6 See Figure 2 below.
Figure 2 The Reversed Seaway Pipeline's Houston to Lake Charles Area Geographic Definition of the Destination Market
( (
4 Both definitions of the destination market include the Reversed Seaway Pipeline's proposed Houston and Beaumont/Port Arthur deliver points. 5 See Mobil Pipe Line Co., 121 FERC 1f 61,268, at P 16 (2007). 6 See Mobil Pipe Line Co., Application of Mobil Pipe Line Company for Authority to Charge Market-Based Rates at StatementA-17-A-21, Docket No. OR07-21-000 (Aug. 24, 2007). (? \ \ 1-8 20111202-5190 FERC PDF (Unofficial) 12/2/2011 4:46:13 PM
( 1 Analyses of the competitive conditions for the two alternative definitions of '· 2 Reversed Seaway Pipeline's Gulf Coast destination market have been
3 performed. As discussed further below, under either definition of the geographic
4 market, the Gulf Coast destination is highly competitive.
5 The Reversed Seaway Pipeline's Cushing origin market is defined geographically
6 to include the crude oil production areas in Oklahoma, Kansas, and Northwest
7 Texas where the crude oil pipelines exiting these production areas primarily
8 transport crude oil to the crude oil pipeline hub at Cushing for transport to
9 refineries outside this area. See Figure 3 below. The alternatives available to
10 the potential shippers on the Reversed Seaway Pipeline at its Cushing origin
11 include the numerous other outbound crude oil pipelines from Cushing and all the (_:_ 12 refineries that are located within the local crude oil production area from which 13 crude oil is delivered to Cushing.
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Figure 3 Oklahoma, Kansas and Northwest Texas Definition of the Reversed Seaway Pipeline Origin Market
( (
1 Further, there are movements from other areas that compete with the outbound
2 pipeline movements from Cushing that should be considered. While I have not
3 attempted to expand the origin market to include all of the alternatives available
4 to the shippers of crude oil produced in these remote production areas, I have
s identified the additional options available to this subset of the potential shippers
6 on the Reversed Seaway Pipeline. Further, I have conducted alternative
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c- 1 competitive analyses that include some of the options available to this subset of
2 potential shippers.
3 The potential shippers of crude oil on the Reversed Seaway Pipeline who
4 transport crude oil into Cushing from remote production areas have all the
5 additional alternatives that are available in these remote production areas or are
6 accessible from these remote production areas. The nearby Texas-New Mexico
7 Permian Basin, from which crude oil is delivered to Cushing by pipeline, is also
8 served by an outbound crude oil pipeline that transports crude oil to East Texas.
9 In East Texas and the adjacent area in Louisiana, there are several refineries.
10 Further, there is a large outbound pipeline (Mid-Valley Pipeline) that transports
11 crude oil to Upper Midwest refineries. There also is an outbound crude oil ( 1_2 pipeline (Sunoco Logistics Kilgore line) that transports crude oil to Houston...... 13 The two more distant major remote production areas from which crude oil is
14 delivered to Cushing are the Rocky Mountain Area (i.e., crude oil produced in
15 Colorado, Wyoming, Montana, and North Dakota including the Bakken oil shale
16 area)? and the Western Canada Area (i.e., in the Canadian Province of Alberta).
17 The alternative crude oil outlets available to the crude oil producers in these
18 remote areas include local refineries, outbound crude oil pipelines, outbound rail
19 movements, and combinations of outbound pipeline and barge movements.
20 Further, there are numerous infrastructure projects that would provide
7 The Rocky Mountain Area as generally defined does not include North Dakota. However, the Bakken oil shale area is in a basin that is in both Montana and North Dakota. Therefore, North Dakota has been included in the definition of the Rocky Mountain Area used here.
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1 incremental outlets for crude oil that are at various stages of planning and ( (
2 development, with several expected to be operational by the time the Reversed
3 Seaway Pipeline commences full operation in 2013.
4 Further, there are other pending pipeline projects that would transport crude oil
s out of Cushing. These include TransCanada's Keystone XL project, and
6 Magellan's Cushing-to-Gulf Coast project. TransCanada's Keystone XL project
7 has shipper support; however, the U.S. Department of State has recently delayed
s a formal decision on permitting TransCanada to begin constructing Keystone XL. 8
9 The final decision is now expected in early 2013, which would be likely to delay
10 ·Keystone XL's completion until early 2015. 9 The Magellan project is less
11 advanced but, if this project were to go forward, it is expected to be completed
12 within one year of obtaining the necessary shipper commitments. The Reversed ( ( 13 Seaway Pipeline is expected to begin initial operations in the second quarter of
14 2012 with a 150 MBD throughpu~ capacity, and to begin full operation in 2013
15 with a 375 MBD throughput capacity. Magellan's potential new pipeline,
16 assuming it obtains firm shipper commitments in 2012, would begin operating
17 during 2013. 10
8 /d. 9 /d. 10 See Statement E. r··- __ 1-12 \_ c 20111202-5190 FERC PDF (Unofficial) 12/2/2011 4:46:13 PM
c-~ C. Summary of Conclusions '" 1 Q. Please summarize your conclusions regarding the competitiveness of the
2 destination and origin markets served by Reversed Seaway Pipeline.
3 A On the basis of the analyses performed, I have concluded that Reversed Seaway
4 Pipeline faces more than sufficient competition in its destination and origin
5 markets for the services it will provide in these areas. This conclusion is based
6 on a detailed analysis of existing and potential competition in its destination and
7 origin markets. The extent of the competition that is faced by Reversed Seaway
8 Pipeline in its destination and origin markets is documented by data and
9 information from the Reversed Seaway Pipeline, published sources, industry
10 sources, and various analyses performed by Navigant.
( l1 Based on capacity data and estimates of the size of the markets served by the '--·~· 12 Reversed Seaway Pipeline, the competitive analysis statistics (i.e., the
13 Herfindahi-Hirschman Indexes or HHis, excess capacity ratios, and the Reversed
14 Seaway Pipeline's estimated capacity shares) are calculated. These statistics
15 demonstrate the highly competitive nature of the Reversed Seaway Pipeline's
16 destination and origin markets. These statistics also demonstrate that there is
17 substantial excess supply capacity available in these markets, which serves to
18 intensify competition. Further, there has been substantial new entry and
19 expansion of existing capacity in the Reversed Seaway Pipeline's markets.
20 There also are many new projects that are underway or are being evaluated in
21 and around the destination and origin markets served by the Reversed Seaway ( \:.__ __ 1-13 20111202-5190 FERC PDF (Unofficial) 12/2/2011 4:46:13 PM
1 Pipeline. For example, there are two pipeline projects other than the Reversed ( (
"'-~ ... ~-/ 2 Seaway Pipeline under development that would transport crude oil from Cushing
3 to the Gulf Coast. These new entry projects demonstrate that new entry would
4 be expected if the Reversed Seaway Pipeline attempted to charge rates that
5 were above the competitive level (i.e., there are no significant barriers to entry).
6 The competitive analysis statistics (the HHI, the Reversed Seaway Pipeline's
7 market share, the excess capacity ratio, and the excess capacity held by others
8 ratio), the substantial volume of excess capacity held by others, and the
9 likelihood of entry, together combine to clearly document that the Reversed
10 Seaway Pipeline will not have market power in its destination or origin markets.
Ill. The Major Issues Addressed in This Testimony
11 Q. Please describe the content of your testimony. ( (
12 A. First, I discuss the nature of the crude oil markets and the role that crude oil
13 pipelines play in these markets. Second, I discuss the views of the U.S.
14 Department of Justice regarding the competitiveness of the lower-48 U.S. crude
15 oil pipeline industry. 11 Third, I discuss the competitive implications of the
16 Reversed Seaway Pipeline being a new entrant in both its origin market and its
11 There have been two prior applications for market-based rates tiled with the Commission by crude oil pipelines. See Rocky Mountain Pipeline System LLC, Application of Rocky Mountain Pipeline System LLC for Authority to Charge Market-Based Rates, Docket No. OR02-11~ooo (July 22, 2002). That application was subsequently withdrawn following an agreement among the parties to the matter. See Mobil Pipe Line Co., Application of Mobil Pipe Line Company for Authority to Charge Market-Based Rates, Docket No. OR0?-21-000 (Aug. 24, 2007). That application was denied by the Commission, but judicial review of the Commission's decision is pending before the U.S. Circuit Court of Appeals for the District of Columbia Circuit.
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( 1 destination market. A new entrant into a market, by definition, makes that market ~ 2 more competitive. 12 Fourth, I discuss the statistical analyses performed for the
3 Reversed Seaway Pipeline's destination and origin markets as well as the other
4 factors that make the crude oil markets to be served by Reversed Seaway
5 Pipeline highly competitive thereby ensuring that it will lack market power.
6 Statements A through H accompanying the application provide the reasoning
7 behind the decisions made in defining the geographic destination and origin
8 markets to be served by the Reversed Seaway Pipeline as well as the reasoning
9 behind the decisions made in computing the statistical measures of market
10 share, market concentration, and excess capacity. The support for these choices
11 consists of information and data on the relevant markets and reasoned ~·.· 12 arguments based on economic principles and relevant Commission decisions. 13 have prepared these Statements, and the arguments presented in them are
14 mine. Enterprise and Enbridge have supplied the factual information in these
15 statements regarding its facilities. Given that the Reversed Seaway Pipeline is
16 not operating, there are no receipt or delivery data for the Reversed Seaway
17 Pipeline.
18 Mark A. Hurley, who is the Senior Vice President of Crude Oil and Offshore
19 Pipelines for Enterprise and whose duties include the management of the
20 existing Seaway pipeline, has also submitted testimony in support of the
12 A potential exception, which does not apply here, could occur if the new entrant were so large that it might be able to profitably exercise unilateral market power.
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1 application for market-based rates. Mr. Hurley's testimony discusses the
2 proposed reversal of the existing Seaway Pipeline to create the Reversed
3 Seaway Pipeline; describes the Reversed Seaway Pipeline's organization,
4 facilities and operations; and explains the reasons why Enterprise and Enbridge
5 are seeking market-based ratemaking authority.
A. The Service Provided by Crude Oil Pipelines
6 Q. What is the service provided by the Reversed Seaway Pipeline and all other
7 crude oil pipelines?
8 A. The service provided by the Reversed Seaway Pipeline and all other crude oil
9 pipelines is the transportation of "crude oil." Crude oil includes the direct liquid
10 production of oil wells, as well as mixtures of the direct liquid production of oil
11 wells with indirect liquid production of oil and gas wells such as natural gasoline (
12 and liquefied petroleum gases.
13 Q. Please describe the characteristics of crude oil.
14 A. Crude oil is not a homogeneous product, but instead is a mixture of various
15 different chemical compounds. These include hydrocarbons, consisting of
16 carbon and hydrogen in varying ratios and in different configurations, and
17 impurities. The characteristics of any particular crude oil will be determined by its
18 own unique combination of these constituent compounds.
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( -- 1 Q. Do crude oil pipelines transport more than one type of crude oil? \ ' 2 A. Yes. Crude oil pipelines can transport all of the types of crude oil that are
3 produced in their origin markets. Some crude oil pipelines move a single
4 commingled stream (with monetary adjustments sometimes being made among
5 shippers to account for differences in the quality of crude oil tendered to the
6 pipeline). Other pipelines segregate the different types of crude oil into batches,
7 which is the same approach used by refined products pipelines to transport
8 multiple grades of gasoline, diesel fuel, and jet fuel in a single pipeline.
9 Q. Does a refinery process either a single crude oil or a fixed blend of crude oils?
10 A. No. A refinery will vary its input stream based on the relative prices of various
11 crude oils, the prices and demand for refined products, and the operating (_ t2 capabilities of the refinery. Crude oil mixing occurs at virtually all refineries and is 13 routinely performed both at the refinery and at points further upstream in the
14 process.
15 The maximization of refinery profits requires the constant adjustment of
16 feedstock mix, reallocation of production flow through the various processing
17 units, and variation in the product output mix. Some changes requiring
18 adjustment are predictable, such as the seasonal shifts in demand for gasoline
19 and heating oil, but the fine tuning of the optimization process requires constant
20 monitoring of market conditions. In the case of the Reversed Seaway Pipeline,
21 many of the refineries in its Gulf Coast destination market are capable of
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1 effectively processing virtually every type of crude oil including substantial
2 amounts of Western Canadian heavy sour crude oil.
3 Q. As a consequence of the above conditions, is it appropriate to assume, in a
4 destination market, that all of the crude oil that a pipeline's competitors supply
5 can be used by the refineries in that destination market?
6 A Yes. First, if a given crude oil could not be processed effectively by the refineries
7 in a destination market, this crude oil would not be delivered to this destination
8 market. Second, while crude oils may vary in their characteristics, they compete
9 directly in the feedstock mix optimization process. Any change in price of a
10 single crude oil will affect the optimal feedstock mix as· refineries adjust their oil
11 supplies and product slate to maximize profits. Except for the simple
12 unsophisticated older refineries, a given refinery can process a blend of both light ( (
13 and heavy crude oils. The refineries on the U.S. Gulf Coast are large and highly
14 sophisticated giving them great flexibility regarding the composition of the crude
15 oil blends that they can process efficiently.
B. The U.S. Department of Justice's View of the Competitiveness of Crude Oil Pipelines in the Lower-48 States
16 Q. Has the U.S. Department of Justice evaluated the competitiveness of the lower-
17 48 U.S. crude oil pipeline industry?
18 A Yes. The competitiveness of the markets served by crude oil pipelines in the
19 lower-48 U.S. states was evaluated by the U.S. Department of Justice (DOJ) in
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c- 1 its 1986 DOJ Oil Pipeline Deregulation Study. 13 The purpose of the Oil Pipeline "· 2 Deregulation Study was to determine whether individual oil pipeline companies
3 faced sufficient competition in all the markets they served to completely
4 deregulate the oil pipeline companies. This is a much greater lessening of
5 regulatory constraints than would occur if an oil pipeline were allowed to charge
6 market-based rates subject to ongoing Commission oversight, including the
7 ability of the Commission to rescind the market-based ratemaking authority. The
8 U.S. Department of Justice study reached the following conclusion regarding
9 crude oil pipelines: "The Department [of Justice] recommends that all existing
10 crude oil pipelines [excluding the Trans Alaska Pipeline System] be
11 deregulated."14 The DOJ elaborated on the reasons why it concluded that all the
12 existing lower-48 crude oil pipelines could be safely deregulated as follows:
~- 13 "The Department has not identified any crude pipeline that 14 presents a clear case for continued federal regulations. In 15 addition, there are theoretical considerations that tend to lessen 16 the need for the continued federal regulation of crude 17 pipelines."15
18 The DOJ further concluded that, not only should all the then-existing crude oil
19 pipelines be deregulated, but, also, that "no newly built oil pipeline be federally
13 OIL PIPELINE DEREGULATION, REPORT OF THE U.S. DEPARTMENT OF JUSTICE, May 1986 (hereinafter "DOJ Deregulation Study"). Although the Oil Pipeline Deregulation Study was published 20 years ago, its conclusions are still valid. The crude oil pipelines in existence at that time are, for the most part, still in place. Some may be idle but could be returned to service readily. Moreover, many new crude oil pipelines are being built. Thus, if anything, crude oil pipeline markets are more competitive today than then. 14 DOJ Deregulation Study at 62.
15 /d.
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1 regulated because regulation is not needed in order to prevent economically
16 2 inefficient behavior by new oil pipelines." While the DOJ concluded that neither
3 new crude oil pipelines nor new product pipelines should be federally regulated, it
4 concluded that the reasons for not regulating new crude oil pipelines were
5 stronger because "the regulation of new crude pipelines in particular can impose
6 significant and costly resource allocation distortions."17 Therefore, the DOJ
7 Study's conclusions support the deregulation of all the existing crude oil pipelines
8 and all new entrant oil pipelines in the lower-48 states, and, thereby, also support
9 the FERC granting such crude oil pipelines, including the Reversed Seaway
10 Pipeline, which is both a crude oil pipeline and a new entrant pipeline, the
11 authority to charge market-based rates.
c. The Competitive Implications of the Reversed Seaway Pipeline Being (( a New Entrant
12 Q. Does the entry of a new pipeline into an origin or destination market inherently
13 make these markets more competitive?
14 A. Yes, with the caveat, which is not relevant here, that a very large new entrant
15 might dominate a market and be able to exercise unilateral market power. The
16 Reversed Seaway Pipeline is a moderate sized crude oil pipeline that could not
17 exercise unilateral market power.
18 Q. Please explain how a new entrant increases the competitiveness of a market.
16 /d. at 143. 17 /d. at xv.
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- _.--,_ ( 1 A. The new entrant, by definition, provides an additional alternative to all shippers "'" 2 from an origin market and to all shippers into a destination market. The new
3 entrant reduces the market shares of all the new entrant's competitors
4 (diminishing the possibility of the unilateral exercise of market power by any
5 existing competitor), and reduces the concentration of the market (diminishing
6 the possibility of anticompetitive coordinated behavior among the existing
7 competitors).
D. Discussion of the Competitive Analyses
1. Statistical and Other Competitive Analyses Performed
8 Q. What statistics have you calculated to help you assess the competitiveness of
9 the markets served by the Reversed Seaway Pipeline? c 10 A. There are four statistics that I have calculated and evaluated. The first two 11 statistics are capacity-based market shares and a capacity-based HHI, which is a
12 measure of market concentration. 18 The pipelines serving a market often have a
13 combined capacity that far exceeds the size of the market being served. There
14 are two methods that are typically used to adjust the individual pipeline's
15 capacities to reflect its greater-than-needed capacities. These methods are the
16 effective capacity method and the adjusted capacity method. 19 I have applied
18 Delivery-based or receipt-based market shares cannot be calculated here, because the Reversed Seaway Pipeline is not yet operating.
19 The effective capacity method was developed by FERC Staff in Williams and was accepted by the Commission. See Williams Pipe Line Co., 68 FERC 1161,136, at 61,665-66 (1994). The adjusted capacity method was used by the U.S. Department of Justice in the DOJ Deregulation Study and has
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1 both of these methods to the Reversed Seaway Pipeline's origin market,
2 producing effective capacity-based market shares and an adjusted capacity-
3 based market shares, and an HHI in each case. For Reversed Seaway
4 Pipeline's destination market, I calculated the capacity-based market shares and
5 HHI's using the unadjusted capacity values of the inbound pipelines because the
6 effective capacity method and adjusted capacity method do not produce
7 meaningful capacity measures for this destination market (i.e., the effective and
B adjusted capacity values would be negative which is not meaningful).20
9 The third statistic that I used is the excess capacity ratio for the market. For the
10 Reversed Seaway Pipeline's destination market, this ratio is calculated as the
11 sum of inbound crude oil pipelines' unadjusted capacities and local crude oil 12 production divided by the estimated crude oil usage by the refineries in the ( ( 13 destination market. For the Reversed Seaway Pipeline's origin market, this ratio
14 is calculated as the sum of the effective capacities of the outbound crude oil
15 pipelines plus estimated crude oil usage by the refineries located in the origin
16 market divided by crude oil supply in the origin market.
been considered by the Commission in various oil pipeline market-based rate matters. See DOJ Deregulation Studay at pp. 31-33 and the Commission's discussion of market statistics in Kaneb Pipe Line Operating Partnership, 83 FERC 1161,183 (1998); Longhorn Pipeline Partners, LP., 83 FERC 11 61,345 (1998); Explorer Pipeline Co., 87 FERC 1161,374 (1999); TE Products Pipe Line, L.P., 92 FERC 11 61,121 (2000); Colonial Pipeline Co., 92 FERC 1161,144 (2000); Wolverine Pipeline Co., 92 FERC 11 61,277 (2000); TE Products Pipe Line, LP., 95 FERC 1161,108 (2001); Chevron Pipe Line Co., 95 FERC 11 61,111 (2001); Colonial Pipeline Co., 95 FERC 1161 ,210 (2001 ); Colonial Pipeline Co., 95 FERC 11 61,377 (2001); Marathon Ashland Pipe Line LLC, 96 FERC 1161,263 (2001); West Shore Pipe Line Co., 100 FERC 11 61 ,001 (2002); Sunoco Pipeline, L.P., 114 FERC 11 61 ,036 (2006); Sunoco Pipeline, L.P., 118 FERC 11 61 ,266 (2007); Mobil Pipe Line Co., 121 FERC 11 61 ,268 (29907); Magellan Pipeline Co., L.P., 128 FERC 1161,278 (2009). 20 These negative values occur because of the very large waterborne deliveries of crude oil to the U.S. Gulf Coast combined with substantial local crude oil production.
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('' 1 The fourth statistic is the excess capacity held by others ratio. For the Reversed \ ' -- 2 Seaway Pipeline's destination market, the excess capacity held by others is
3 calculated as the total capacity to supply the market minus estimated local
4 refinery crude oil input minus estimated excess (unused) capacity on the
5 Reversed Seaway Pipeline. 21 The excess capacity held by others ratio equals
6 the calculated excess capacity held by others divided Qy the estimated deliveries
7 by the Reversed Seaway Pipeline. 22 For the Reversed Seaway Pipeline's origin
8 market, the excess capacity held by others is calculated as the local capacity to
9 absorb crude oil minus crude oil available in the origin market minus the excess
10 (unused) capacity in the Reversed Seaway Pipeline. The excess capacity held
11 by others ratio equals the calculated excess capacity held by others divided Qy c--- 12 the estimated receipts by the Reversed Seaway Pipeline.23
''\ ''--·-- 13 Q. Please discuss your views on how these statistics should be interpreted.
14 A. The capacity-based market share for the pipeline seeking permission to charge
15 market-based rates and the capacity-based HHI for the overall market both
16 should be considered. However, if the HHI for the market is relatively low, then
17 the market share for the pipeline seeking permission to charge market-based
18 rates need not be considered. If the HHI for the market is relatively high, then
19 the market share of the pipeline should be evaluated. The higher the HHI value,
21 Given that the Reversed Seaway Pipeline is not operating, its excess capacity is estimated to be 10% of its capacity. 22 Given that the Reversed Seaway Pipeline is not operating, its estimated deliveries are estimated to be 90% of its capacity. 23 Given that the Reversed Seaway Pipeline is not operating, its estimated receipts are estimated to be 90% of its capacity.
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1 the more concentrated the market and the greater the risk that the suppliers
2 might be able to profitably charge prices that were above competitive levels. The
3 HHI threshold should be 2,500, which would result when four equally-sized
4 competitors serve the market (i.e., if the HHI for a given market is 2,500 or less,
5 then the market should be presumed workably competitive). The Commission
6 Staff and intervenors in certain prior market-based rate proceedings have argued
7 for a 1 ,800 threshold, which would result when between five and six equally-
s sized competitors serve the market. (When five equally-sized competitors serve
9 a market, the HHI is 2,000 and, when six equally-sized competitors serve a
10 market, the HHI is 1 ,667.)
11 While the Commission has not adopted a threshold standard for the HHI, it has
12 consistently granted market-based ratemaking authority to oil pipelines in
13 markets where the HHI's were 2,500 or less and the pipeline requesting market-
14 based rates did not have a very high market share.24 Further, the Commission
15 has approved market-based rates for oil pipelines in markets where the HHI was
16 above 2,50025 and even just under 3,000. In the case where the HHI was just
17 under 3,000, the oil pipeline's market share was just under 30 percent.26
24 Williams Pipeline Co., eta/., 71 FERC ,-r 61,291, at 62,141-62 (1995) (Opinion No. 391-A); id. at 61,142 (discussing Eau Claire); id. at 61,142-43 (discussing Fargo). 25 See id. at 62,136-38 (discussing Quincy); Williams Pipeline Co., 68 FERC ,-r 61,136, at 61,681-82 (1994) (Opinion No. 391) (discussing Minneapolis/St. Paul). 26 See Kaneb Pipe Line Operating Partnership, L.P., 83 FERC ,-r 61,183 (1998) (discussing Kaneb at Cheyenne). (( 1-24 20111202-5190 FERC PDF (Unofficial) 12/2/2011 4:46:13 PM
~-··- ( 1 Where the HHI is 2,500 or less, there would be no need to consider the individual
2 pipeline's market share. In such a market, no participant could exercise market
3 power. If the HHI is at or above 2,500, or if other specific factors indicate that the
4 exercise of market power might be possible, the market share of the pipeline
5 seeking market-based rates (as well as other factors) should be examined. If the
6 pipeline's market share is low (e.g., less than 10 percent), the pipeline could not
7 have market power no matter how high the HHI or how few the number of market
8 participants and should be allowed to charge market-based rates. 27 In such a
9 case, a high HHI would be due to the high market share of one of the pipeline's
10 larger competitors.28 Further, a pipeline should be considered incapable of
11 exercising market power if its market share is 20 percent or less when there are
("--12 at least four market participants with market shares of 10 percent or more
''.... ,. .. · 13 regardless of the HHI value. Also, it certainly is possible for a pipeline's market
14 share to be much higher than 20 percent and for it not to be in a position to
15 exercise market power in a high HHI market.29 However, in that case, the market
27 In Buckeye Pipeline Co.,53 FERC ,-r 61,473 (1990), the Commission recognized that a pipeline with a low market share in a high HHI market could be safely allowed to charge market-based rates. For example, Buckeye's low market share in the Indianapolis destination market was sufficient for the Commission to allow Buckeye to charge market-based rates despite an HHI of 4,607 for the destination market. 53 FERC ,-r 61,473, at 62,669-70. 26 In Buckeye, the Commission concluded this was the case for Buckeye in the Indianapolis destination market where Buckeye had a market share of less than 2% when the HHI was 4,607 for the destination market. The high HHI was due to a market participant that had a market share over 64%. In Kaneb, the Commission, found that this was the case for Kaneb, in Cheyenne, WY, where Kaneb had a market share just below 30% when the HHI was 2,742. Kaneb Pipe Line, 83 FERC ,-r 61,183, at 61,761-62. 29 The Commission has concluded that the pipeline requesting market-based rates had no market power in a high HHI market despite having a market share above 20%. This occurred in Buckeye for the Columbus, OH destination market and in Kaneb for the Cheyenne, WY destination market. Other factors such as excess supply capacity also were taken into account by the Commission. Buckeye Pipeline Co.,
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1 would have to be fully investigated. The market participants most likely to be
2 able to exercise market power in a high HHI market are the largest suppliers to
3 that market.
4 A high excess capacity ratio is a strong pro-competitive factor that the
5 Commission has also considered (i.e., one with a value of 1.1 or higher should
6 be sufficient). 30 Given the high fixed costs of liquids pipelines, oil pipeline
7 companies have a very strong incentive to achieve a high capacity utilization.
8 The existence of excess capacity as documented by the excess capacity ratio
9 indicates that it is highly unlikely that any market participant could exercise
10 market power, because its competitors have unused capacity that they could use
11 to improve their profitability. ( 12 The presence of a large amount of excess capacity in a market (i.e., a high
13 excess capacity ratio) makes a market more competitive independent of which of
14 the competitors has this excess capacity. However, the excess capacity held by
15 the competitors to an applicant pipeline places a stronger competitive constraint
16 on the pricing behavior of the applicant pipeline. If the excess capacity held by
17 others ratio were to equal 0.2, then there is sufficient capacity available to absorb
18 20% of the applicant pipeline's volumes which should be sufficient to thwart rate
53 FERC 11 61 ,473, at 62,671 and Kaneb Pipe Line, 83 FERC 11 61,183, at 61,761-62. 30 In Buckeye, the Commission cited high excess capacity as a factor in finding a lack of market power in Pittsburgh (53 FERC 1161,473, at 62,669), Indianapolis (id. at 62,670), Detroit (id. at 62,670), and Columbus (id. at 62,671). In Kaneb, excess capacity was a factor in the Commission's findings in Fargo and Omaha (83 FERC 1161,183, at 61 ,761), Lincoln (id.) and Cheyenne (id. at 61 ,767-62).
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(~-- 1 increases above competitive levels by the applicant pipeline. If the excess "' 2 capacity ratio held by others is 1.0 or greater, then there is sufficient excess
3 capacity held by others to be able to absorb 100% of the applicant pipeline's
4 volumes.
5 2. The Competitiveness of the Reversed Seaway Pipeline's Gulf 6 Coast Destination Market
7 Q. Applying the analysis you have just described, please summarize the results of
8 your analyses of the competitiveness of the Reversed Seaway Pipeline's Gulf
9 Coast destination market.
10 A. The results of the statistical analyses of the competitiveness of the Reversed
11 Seaway Pipeline's Gulf Coast destination market are summarized in Table 1
( ~-- 12 below. The results are shown for the two alternative geographic definitions of the
'---· 13 Reversed Seaway Pipeline's Gulf Coast destination market. The two geographic
14 definitions are: (1) the most appropriate Gulf Coast Area definition which
15 extends from Corpus Christi, Texas on the west to Mobile, Alabama on the east;
16 and (2) the Houston to Lake Charles Area definition, which is the smallest
17 plausible definition of the destination market. Statement A contains a detailed
18 discussion of these alternative geographic definitions of the Reversed Seaway
19 Pipeline's destination market. For each of the two geographic destination market
20 definitions, Table 1 below presents the results of the HHI calculations on the
21 basis of the unadjusted capacities, which produces higher (less favorable) HHI
22 results than are typically produced by using either the effective capacity method
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1 or adjusted capacity method measures.31 The Reversed Seaway Pipeline's
2 market share results also are calculated based on unadjusted capacity data. The
3 excess capacity ratio and the excess capacity held by others ratio also are
4 presented. Delivery-based market shares for the pipeline cannot be calculated
s because the pipeline is not yet in operation (i.e., there are no delivery data).
Table 1 Summary of Capacity-Based Analysis Results for the Reversed Seaway Pipeline's Destination Market on the Gulf Coast
Excess Reversed Capacity Seaway Excess Held by Market Capacity Others Definition of the Destination Market HHI Share Ratio Ratio
/ Gulf Coast Area 26 4.6% 1.23 4.41 I \,,_ Houston to Lake Charles Area 169 6.5% 1.53 5.78
Sources: Tables G.1 and G.2.
6 Q. Please discuss the statistical results shown in Table 1.
7 A The Reversed Seaway Pipeline has a low capacity-based market share and
s there is a great deal of excess capacity and excess capacity held by others under
9 the two geographic definitions of its destination market. Further, the unadjusted
10 capacity-based HHI's are very low (less than 200) under the two definitions of the
31 The two adjusted capacity measures, the effective capacity method and the adjusted capacity method, cannot be calculated for any of the definitions of the destination market, because waterborne deliveries of crude oil plus local crude oil production exceed local refinery use of crude oil. Under this circumstance, the numerical calculations of the two adjusted capacity measures produce meaningless negative numbers.
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1 destination market. Thus, under either of these two geographic definitions, the
2 Reversed Seaway Pipeline could not profitably charge rates above competitive
3 levels for its deliveries to this destination market.
4 3. The Competitiveness of the Reversed Seaway Pipeline's 5 Cushing Origin Market
6 Q. Please summarize the results of your analyses of the competitiveness of the
7 Reversed Seaway Pipeline's Cushing Origin Market.
8 A. The Reversed Seaway Pipeline has a single receipt point at Cushing, OK.
9 Statement A contains a detailed discussion of the geographic definition of the
10 Cushing origin market which consists of the crude oil production area in
11 Oklahoma, Kansas, and Northwest Texas. The results of the statistical analyses
12 of the competitiveness of the Cushing origin market are presented in Table 2 for c 13 the Reversed Seaway Pipeline's Cushing origin market. These statistical
14 analyses are performed using two different measures of market size. For most
15 crude oil pipeline origin markets, market size would be measured by the amount
16 of crude oil produced within the origin market, and this is the first definition of
17 market size for the Cushing origin market used in Table 2 (i.e., the column in
18 Table 2 labeled "Local Crude Oil Production Only"). Cushing, however, is a
19 major crude oil pipeline hub that also receives crude oil from remote production
20 areas.
21 The second definition of the market size for the Cushing origin market includes
22 both local crude oil and production and estimated crude oil deliveries to Cushing
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1 from remote production areas (i.e., the column in Table 2 labeled "Local Crude
2 Oil Production and Crude Oil Deliveries"). For local crude oil production, the only
3 competitors to the Reversed Seaway Pipeline in its Cushing origin market are
4 other crude oil pipelines that transport crude oil out of the Cushing origin market
5 and refineries within the Cushing origin market. For crude oil delivered to
6 Cushing from remote production areas, the competitors to the Reversed Seaway
7 Pipeline likewise include refineries within and crude oil pipelines exiting the
8 Cushing origin market plus all the alternatives available within the remote
9 production areas and all the alternatives accessible from the crude oil pipelines
10 that transport the crude oil from the remote production areas to Cushing.
11 Table 2 presents the effective capacity method HHis, the adjusted capacity 12 method HHis, the Reversed Seaway Pipeline's effective and adjusted capacity- ( ( 13 based market shares within the Cushing origin market, the excess capacity ratio,
14 and the excess capacity held by others ratio. A receipt-based market share
15 cannot be calculated for the Reversed Seaway Pipeline because it is not yet
16 operating.
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Table 2 Summary of Capacity-Based Analysis Results for the Cushing Origin Market
Market Size Definition Local Crude Oil Production and Local Crude Oil Crude Oil Market Statistic Production Only Deliveries Effective Capacity HHI 1,126 1,126 Reversed Seaway Pipeline's 18.0% 18.0% Effective Capacity Market Share Excess Capacity Ratio 3.84 1.31 Excess Capacity Held by Others Ratio 4.45 1.34
Adjusted Capacity HHI 909 1,003 Reversed Seaway Pipeline's 9.1% 11.1% Adjusted Capacity Market Share
Sources: Tables G.14 and G.15. --···- ( 1 ""'---·· 2 Q. Please discuss the statistical results shown in Table 2.
3 A. Under both definitions of the size of the Cushing origin market, the effective
4 capacity-based HHis for both definitions of market size is under 1,200 (i.e.,
5 substantially below the conservative 1,800 threshold suggested by Staff and
6 intervenors in earlier proceedings). The Reversed Seaway Pipeline's effective
7 capacity-based market share is less than 20% for both definitions of market size.
8 The excess capacity ratio and the excess capacity held by others ratio are both
9 1.3 or higher, which indicates substantial excess capacity. For both definitions of
10 market size, the adjusted capacity-based HHis are below 1 ,050 and the market
11 shares are less than 11.5%. These statistics indicate that the Cushing origin
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1 market is highly competitive and that the Revised Seaway Pipeline could not
2 profitably charge rates above competitive levels for movements out of the
3 Cushing origin market.
4 The statistical analyses summarized in Table 2 only include as competitors to the
5 Reversed Seaway Pipeline the refineries within and the crude oil pipelines exiting
6 the Cushing origin market. As a consequence, the statistics presented in the
7 second column of Table 2 (which includes crude oil from remote production
8 areas) understate the extent of competition faced by the Reversed Seaway
9 Pipeline in its Cushing origin market. However, since the statistics in the second
10 column of Table 2 indicate that the Reversed Seaway Pipeline faces ample
11 competition from just the competitors located.in the Cushing origin market, it is I
12 not essential for purposes of determining the competitiveness of the Cushing ( .· \, ( 13 origin market to identify all the competitive alternatives located outside the
14 Cushing origin market. Nevertheless, despite the fact that the statistics in the
15 second column of Table 2 indicate that the Cushing origin market is highly
16 competitive, I have performed analyses that evaluate the implications of
17 introducing some of the competitors to the Reversed Seaway Pipeline that are
18 located outside the Cushing origin market.32
32 The results of these analyses are discussed in Statement G.
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(/ 1 Q. What are the expected types of crude oil that will be transported by Reversed -,_ 2 Seaway Pipeline and where are these crude oils produced?
3 A The Reversed Seaway Pipeline is expected to transport both light sweet crude oil
4 (e.g., WTI) and heavy sour crude oil (e.g., Western Canadian Select or WCS
5 which is a bitumen blend) on its pipeline. The light crude oil is produced in the
6 production area that defines geographies of the Cushing origin market, the Rocky
7 Mountain Area, and the parts of the Texas-New Mexico Permian Basin Area that
8 are not included in the Cushing origin market. The source of the heavy sour
9 crude oil will be the Western Canada Area.
10 Q. What are the alternatives, in addition to those in the Cushing origin market, that
11 are available to the producers of the crude oil from the Western Canada Area?
(:_ 12 A Western Canadian crude oil producers have options for selling their production 13 that do not involve Reversed Seaway Pipeline or the Cushing origin market.
14 First, they can sell their crude oil to refineries in Western Canada. Second, they
15 can transport their crude oil by pipeline to the refineries in the U.S. Upper
16 Midwest (i.e., the refining centers in Minnesota, Wisconsin, Illinois, Indiana,
17 Michigan, Ohio, and Kentucky), in Eastern Canada, on the Canadian West
18 Coast, and in the U.S. Northwest (i.e., the refineries in Washington State). This
19 crude oil also can be further transported using tankers from the Canadian West
20 Coast to California and Asia. Third, they can transport their crude oil by pipeline
21 for use by the refineries in the Rocky Mountain Area.
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1 Q. What are the alternatives, in addition to those in the Cushing origin market, that
2 are available to the producers of the crude oil from the Rocky Mountain Area?
3 A. The crude oil producers in the Rocky Mountain Area can sell their crude oil to
4 refineries in the Rocky Mountain Area and can transport their crude oil by
5 pipeline to refineries in the U.S. Upper Midwest and Eastern Canada.
6 Q. What are the alternatives, in addition to those available in the Cushing origin
7 market, that are available to the producers of the crude oil for the Texas-New
8 Mexico Permian Basin Area?
9 A. The crude oil producers in the Texas-New Mexico Permian Basin Area can sell
10 their crude oil to refineries in Western Texas and eastern New Mexico and can
11 transport their crude oil by pipeline to East Texas from which the Northeastern
12 Texas and Northwestern Louisiana area refineries can be supplied. The crude ( (_
13 oil also can be transported by other pipelines to refineries in the Upper Midwest
14 and on the Gulf Coast.
15 4. Excess Capacity in the Destination and Origin Markets
16 Q. How does the existence of excess capacity held by Reversed Seaway Pipeline's
17 competitors make the markets to be served by the Reversed Seaway Pipeline
18 more competitive?
19 A. The ability of competitors to very quickly take business from the Reversed
20 Seaway Pipeline if it were to attempt to charge supra-competitive prices for
21 movements from its origin market or to its destination market is determined, in
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( .~· 1 part, by the level of excess capacity. In its destination market, the existing '· 2 excess capacity of other inbound crude oil pipelines and the excess waterborne
3 delivery capacity are important. In its origin market, the ability of the Reversed
4 Seaway Pipeline's competitors to take business away depends on the excess
5 capacity of competing outbound crude oil pipelines and on the existing excess
6 capacity of local refineries. These existing competitors can expand utilization
7 and thereby output very quickly, which makes tliem particularly strong
8 competitors. Of course, a new pipeline that had entered the market would
9 ·provide a similar level of competition.
10 Q. Do the Reversed Seaway Pipeline's competitors have excess capacity?
11 A Yes. As summarized in Tables 1 and 2 above, the Reversed Seaway Pipeline's ~- 12 competitors in both its destination and origin markets have excess capacity which 13 could be used to take business from the Reversed Seaway Pipeline if it tried to
14 raise rates its rates above competitive levels. For the Reversed Seaway
15 Pipeline's origin and destination markets, the excess capacity ratio is 1.2 or
16 higher, and the excess capacity held by others ratio is above 1.3. There is
17 sufficient excess capacity held by others to accommodate all the expected
18 movements on the Reversed Seaway Pipeline. Both the Reversed Seaway
19 Pipeline and its competitors have a strong financial incentive to operate at high
20 utilization rates and thereby enhance the profitability of their pipelines.
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1 5. New Entry into the Markets Served by Reversed Seaway 2 Pipeline
3 Q. Has there been recent new entry and is more new entry expected shortly in the
4 destination and origin markets served by the Reversed Seaway Pipeline?
5 A. Yes. There has been substantial new entry into the destination and origin
6 markets that are served by the Reversed Seaway Pipeline. More has been
7 approved, and still more is planned. The potential for new entry into the
8 Reversed Seaway Pipeline origin and destination markets functions as a very
9 real and strong competitive constraint on the pricing behavior of the R~versed
10 Seaway Pipeline. Further, there is new entry of outbound crude oil pipelines
11 planned (including capacity expansions of existing pipelines) in Western Canada,
12 the Rocky Mountain Area (particularly in the Bakken oil shale area), and in the
13 Texas-New Mexico Permian Basin. These are all major crude oil production ( (
14 areas that supply crude oil to the Cushing origin market. There already is strong
15 competition between the new entrant Reversed Seaway Pipeline and the other
16 potential new entrant pipelines for movements from Cushing to the Gulf Coast
17 (i.e., the ongoing competition for shipper commitments).
18 6. Overall Conclusions Based on the Above Results
19 Q. What is your overall interpretation of the results discussed above?
20 A. The market share, market concentration, and excess capacity ratio statistics
21 indicate that both the origin and destination markets that are served by the
22 Reversed Seaway Pipeline are workably competitive. In addition, there is (( 1-36 '· --- 20111202-5190 FERC PDF (Unofficial) 12/2/2011 4:46:13 PM c 1 substantial excess capacity in these markets, there has been recent new entry in 2 and around the markets served by Reversed Seaway Pipeline, and there are
3 new pipeline projects that have been approved and other pipeline projects that
4 are planned. Further, there are additional important pro-competitive factors
5 discussed in detail in Statement H. Therefore, the tariff rates for the Reversed
6 Seaway Pipeline could not profitably be raised above competitive levels.
7 IV. Structure and Content of The Statements Accompanying Seaway's 8 Application
9 Q. Please describe the structure and content of the Statements accompanying the
10 application for market-based rates for the Reversed Seaway Pipeline.
11 A. The structure and content of this testimony and the accompanying Statements
( .. - 12 conform with the filing requirements set forth by the Commission in Order No.
~·13 572 in Docket No. RM 94-1-000 on Market-Based Ratemaking for Oil Pipelines
14 issued on October 28, 1994 (hereinafter Order 572). Order 572 called for nine
15 Statements (denoted as Statements A through I) to be filed. These nine
16 Statements are:
17 Statement Content of the Statement
A Geographic Markets 8 Product Markets c Pipeline Facilities and Services D Competitive Alternatives E Potential Competition F Maps G Market Power Measures H Other Factors I Proposed Testimony c'·.._ ___ - 1-37 20111202-5190 FERC PDF (Unofficial} 12/2/2011 4:46:13 PM
1 Q. Please describe the Statements that define the Reversed Seaway Pipeline's
2 product and geographic markets.
3 A Statement B defines the Reversed Seaway Pipeline's product markets and
4 discusses the markets for crude oil and the role of crude oil pipelines in these
5 markets. The Reversed Seaway Pipeline provides the service of transporting
6 "crude oil" which consists of a wide range of types of crude oil. All of the
7 Reversed Seaway Pipeline's competitors compete with it for the business of
8 supplying/delivering or absorbing/shipping all types of crude oil. 33 Further, there
9 are existing competitors with excess capacity who could make these movements.
10 Finally, shippers exchange and otherwise trade34 crude oil to reduce or eliminate
11 the need for crude oil transportation.
12 Based in part on the definition of the product market in Statement B, the
13 geographic markets are defined in Statement A The application seeks authority
14 to charge market-based rates for movements from the Reversed Seaway
15 Pipeline's Cushing origin and to its Gulf Coast destination (including the Houston
16 and Beaumont-Port Arthur delivery points).
17 Statement A begins by contrasting the origin-destination market analytical
18 approach and the corridor market analytical approach, and concludes that the
19 former approach is appropriate. Geographic origin markets typically are defined
33 The inbound refined products pipelines in destination markets compete with the supply of all types of crude oil. 34 In addition to exchanges, there are buy-sell agreements with a single counterpart and separate transits involving a sale of crude oil at one location and the purchase of crude oil at another location.
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(-' 1 by the location of the crude oil producing areas that use a pipeline to transport
2 crude oil. The Reversed Seaway Pipeline's Gulf Coast destination market
3 consists, at minimum, of the Houston to Lake Charles Area which contains the
4 Reversed Seaway Pipeline's Houston and Beaumont-Port Arthur delivery points.
5 However, the most appropriate definition of the Reversed Seaway Pipeline's Gulf
6 Coast destination market is the Gulf Coast Area ranging from Corpus Christi,
7 Texas on the west to Mobile, Alabama on the east. The Gulf Coast Area
8 definition is the most appropriate because crude oil delivered to Houston or
9 Beaumont-Port Arthur is subsequently delivered to locations throughout the Gulf
10 Coast Area by barges and tankers. Further, there are numerous crude oil
11 pipeline linkages within the Gulf Coast Area. The Reversed Seaway Pipeline's .. ( 12 Cushing origin market is defined geographically as the area containing the crude '--- ,' 13 · oil production that, if not processed by refineries located within the production
14 area, is primarily delivered by pipeline to Cushing for movement outside the
15 Cushing origin market. Brief descriptions of the Reversed Seaway Pipeline's
16 destination and origin markets are provided above. A detailed description is
17 provided in Statement A.
18 Q. Please discuss the Statements that describe the Reversed Seaway Pipeline's
19 facilities and services and the competition that Reversed Seaway Pipeline faces.
20 A. Statement C describes the Reversed Seaway Pipeline's facilities and services.
21 This Statement primarily is a data source. Given that the Reversed Seaway
22 Pipeline has not yet begun operating, data on its receipts and deliveries do not
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1 exist. For the purposes of estimating the excess capacity ratio and the excess
2 capacity held by others ratio, the total receipts and deliveries of the Reversed
3 Seaway Pipeline were set equal to 90% of its throughput capacity.
4 Statement D defines the competitive alternatives to the Reversed Seaway
5 Pipeline. The universal use of product exchanges and other types of crude oil
6 trading serves to make all the competitive alternatives to the Reversed Seaway
7 Pipeline viable options in its origin and destination markets. The specific
8 competitive alternatives available in both the destination and origin markets are ., 9 identified and listed in Statement D. Capacity data are collected or estimated for
10 all competitors and for all other market participants. I did not attempt to collect
11 receipt, delivery, and output data from the other market participants, because 12 attempts in earlier matters to collect such data from competitors were not fruitful. ( ( 13 Further, the receipt and delivery data for other market participants cannot be
14 reliably estimated. As a result, only capacity-based market share and HHI
15 analyses can be performed. Statement D contains a detailed description of how
16 all the necessary data were collected or estimated.
17 Statement E identifies potential competitors to the Reversed Seaway Pipeline
18 and discusses the numerous pending new entrants to the markets served by the
19 Reversed Seaway Pipeline.
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"" --" ( 1 Q. What maps are included in Statement F? ~ 2 A. Figure F.1 presents an overview of the Reversed Seaway Pipeline showing its
3 origin, destination, and route. Figures F.2 and F.3 show the areas included in the
4 two alternative geographic definitions of the Reversed Seaway Pipeline's Gulf
5 Coast destination market: (1) Figure F.2 shows the Gulf Coast Area (Corpus
6 Christi, Texas to Mobile, Alabama) definition; and (2) Figure F.3 shows the
7 Houston to Lake Charles Area definition. The maps in Figures F.2 and F.3
8 identify the Reversed Seaway Pipeline and the competing inbound crude oil
9 pipelines supplying each area from outside the area. Figure F .4 presents a
10 schematic description of the crude oil supply and distribution network in the
11 vicinity of the Reversed Seaway Pipeline's Houston delivery location. Figure F.5
shows the pipelines exiting the Cushing Hub within the Reversed Seaway (_ 12
_/~13 Pipeline's Cushing origin market. Figure F.6 shows inbound crude oil pipelines
14 supplying the Cushing Hub within the Reversed Seaway Pipeline's Cushing
15 origin market. Figure F.7 shows the outbound crude oil pipelines in the U.S.
16 Rocky Mountain Area, and Figure F.8 shows the outbound crude oil pipelines in
17 Western Canada.
18 Q. Please describe Statements G and H which discuss the market power measures
19 and the other factors affecting the competitiveness of the Reversed Seaway
20 Pipeline's markets.
21 A. Statement G starts with a discussion of how to calculate and interpret the market
22 power measures such as the market share and HHI statistics. Alternative c ~" 1-41 20111202-5190 FERC PDF (Unofficial) 12/2/2011 4:46:13 PM
1 threshold criteria to apply to the HHI and market share statistics are discussed.
2 A threshold of 2,500 for the HHI statistics is recommended, but no independent
3 threshold is recommended for the market share. However, if the pipeline
4 requesting market-based rates has a low market share (e.g., less than 10%),
5 then the pipeline could not profitably exercise market power. Also, the strong
6 pro-competitive effects of the Reversed Seaway Pipeline's other competitors
7 having excess supply capacity are discussed.
8 The market share, HHI, excess capacity ratio, and excess capacity held by
9 others ratio statistics are calculated for the destination and origin markets. The
10 market share and HHI statistics for these markets are calculated using capacity
11 data. Also, the competitive analyses developed in Statement H are discussed
12 briefly in Statement G.
13 Statement H discusses additional factors, other than the market share, HHI,
14 excess capacity ratio, and excess capacity held by others ratio, that demonstrate
15 the competitiveness of the markets served by the Reversed Seaway Pipeline.
16 These other factors include crude oil exchanges and trades, excess capacity and
17 new entry that were taken into consideration in Statement G in reaching the ,
18 conclusion that Reversed Seaway Pipeline's markets are sufficiently competitive
19 to warrant market-based rates. Finally, Statement H presents a discussion of the
20 U.S. DOJ's view that all lower-48 crude oil pipelines face sufficient competition
21 for them to be deregulated.
( (_ 1-42 ·~ 20111202-5190 FERC PDF (Unofficial) 12/2/2011 4:46:13 PM
c 1 The results presented in Statements G and H clearly demonstrate that there is ~~ " 2 more than sufficient competition to warrant granting authority to charge market-
3 based rates for all movements on the Reversed Seaway Pipeline from its origin
4 in Cushing, Oklahoma and to its Houston, Texas and Beaumont-Port Arthur
5 delivery points.
6 Q. Does this conclude your testimony?
7 A. Yes.
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APPENDIX A
RESUME OF DR. GEORGE. R. SCHINK
( 20111202-5190 FERC PDF (Unofficial) 12/2/2011 4:46:13 PM
NAVIGANT ( ECONOMICS '"'-
GEORGE R. SCHINK, PHD MANAGING DIRECTOR & PRINCIPAL
1801 K Street, NW, Suite 500 Washington, D.C. 20006
direct: 202.481.8318 main: 202.973.2400 Email: [email protected]
810/SUMMARY George R. Schink's areas of expertise include energy economics, regulatory economics, financial economics related to the cost of service for regulated entities, antitrust economics, damage and liability .,analyses, econometrics, and statistics. Dr. Schink has done extensive research in energy markets including electricity, natural gas, crude oil, and refined products. Dr Schink also has extensive experience with regulatory matters regarding electric utilities, gas distribution utilities, oil pipelines, gas pipelines, telecommunications, webcasting, and cable television. Dr. Schink has worked on mergers and other antitrust matters for companies in energy and other industries and also has done liability and damage analyses for these same industries. Dr. Schink also has done substantial work related to motor vehicle markets including analyses of the demand and supply of motor vehicles and of the markets served by individual dealers. Dr. Schink has testified as an expert witness in federal and state courts and before federal and state regulatory bodies including the Federal Energy Regulatory Commission, the Copyright Arbitration Royalty Panel, and the Federal Communications Commission. Dr. Schink also has testified before Congressional committees and has made presentations to the Federal Trade Commission on· behalf of companies seeking to merge.
George R. Schink has taught economics while at the University of Maryland and as an Adjunct Associate Professor at the Wharton School of the University of Pennsylvania from which he previously earned his Ph.D. degree in economics. He was at Wharton Econometric Forecasting Associates (currently Global Insight) for 16 years where he was involved in a wide variety of consulting, forecasting and econometric modeling activities including analyses of regulated industries, the energy industry, the auto industry, the telecommunications industry, the cable television industry and various consumer product and service industries. Also, Mr. Schink developed and used a large-scale macro econometric model of the US economy while at WEFA, and he continues to do consulting regarding the economy-wide effects of public policies and of the activities within a given sector of the economy.
EDUCATION Ph.D., Economics, University of Pennsylvania, 1971.
Thesis (Unpublished): Small Sample Estimates of the Variance Covariance Matrix of Forecast Error for Large Econometric Models: The Stochastic Simulation Technique. Won William Carey Prize for best Ph.D. thesis in economics at the University of Pennsylvania, 1971. Thesis Advisor: Professor Lawrence R. Klein.
B.S., Economics, University of Wisconsin at Madison, 1964.
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N!\VIGANT ECONOMICS
PRESENT POSITION NAVIGANT ECONOMICS, Managing Director & Principal, January 2011-present
OTHER POSITIONS HELD LECG, LLC, July 1994- January 2011 Director, Dr. Schink's areas of expertise include energy economics, regulatory economics, financial economics related to the cost of service for regulated entities, antitrust economics, damage and liability analyses, econometrics, and statistics. Dr. Schink has done extensive research in energy markets including electricity, natural gas, crude oil, and refined products. Dr Schink also has extensive experience with regulatory matters regarding electric utilities, gas distribution utilities, oil pipelines, gas pipelines, telecommunications, webcasting, and cable television. Dr. Schink has worked on mergers and other antitrust matters for companies in energy and other industries and also has done liability and damage analyses for these same industries. Dr. Schink also has done substantial work related to motor vehicle markets including analyses of the demand and supply of motor vehicles and of the markets served by individual dealers. Dr. Schink has testified as an expert witness in federal and state courts and before federal and state regulatory bodies including the Federal Energy Regulatory Commission, the Copyright Arbitration Royalty Panel, and the Federal Communications Commission. Dr. Schink also has testified before Congressional committees and has made presentations to the Federal Trade Commission on behalf of companies seeking to merge.
AUS CONSULTANTS, INDUSTRY ANALYSIS GROUP, West Conshohocken, PA, June 1988- July 1994. Chairman and Chief Executive Officer, June 1988- July 1994. Responsible for overall management and strategic guidance of the Industry Analysis Group, as well as the design and execution of consulting projects related to the automotive, energy, utility, and telecommunications industries. These projects include market analysis, development of sales volume and revenue models, development of price and cost models, industry studies, and analysis of the impact ( ( of government policy and regulatory changes on these industries. The results of these studies are provided to clients as reports and in direct presentations to senior management. Also, Dr. Schink has extensive experience in presenting testimony before regulatory bodies and in the courts.
THE WEFA GROUP (IHS Global Insight), Bala Cynwyd, PA, June 1972- May 1988. Senior Vice President, Consulting Services, May 1987 - May 1988.
Vice President, Research and Development, June 1983- May 1987. Responsible for the development, enhancement, specification, maintenance of the Wharton econometric models. Also responsible for design, execution, and economic content of large contract research projects, preparation and presentation of testimony, general quality control of Wharton economic analysis and forecasting products, internal training of economic staff, and design inputs for econometric and statistical software.
Key contract research projects include an analysis of the macroeconomic impacts of local content legislation and an analysis of the economy-wide effects of the FCC access charge plan. Major model development projects include a redesign of Wharton's multiregion model of New York State and respecification and updating of Wharton's Quarterly Model.
Vice President, U.S. Modeling Services, January 1980- June 1983. Responsible for coordinating model development/enhancement activities of Wharton's U.S. forecasting services, including the Long-Term Forecasting Model, the Quarterly Forecasting Model, and Industry Planning Service Model.
Worked with the marketing group and the model project directors to develop new sources of revenue for the U.S. model-based forecasting services from both subscription and contract research sources.
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NAVIGANT ( ECONOMICS ~- Executive Director, Wharton Annual (Long-Term) Model Project, January 1977 - December 1979. Responsible for directing model development/enhancement, forecasting, scenario analysis, contract research, forecast review meetings, and client support activities for U.S. Long-Term Forecasting Service.
Under the direction of Dr. Schink, the Wharton Annual Model was expanded in scope (from 850 variables to 2300 variables) to incorporate energy detail, demographic detail, and producer price detail. These changes were designed to enhance the Annual Model's usefulness for long-term planning and analysis. Research and development contracts to support the Long-Term Model enhancement activities were obtained from the Federal Energy Administration, the Electric Power Research Institute, the Office of Naval Research, Ross Laboratories, and the U.S. Department of Energy.
These model enhancement activities have led to contracts to perform long-term policy and scenario analyses for the groups supporting development as well as contracts from others such as the American Gas Association, the Whirlpool Corporation, the New York Stock Exchange, the General Accounting Office, the Joint Economic Committee, the U.S. Department of Commerce, Sun Oil Company, and the U.S. Department of Defense.
Executive Director, Special Projects, June 1972 -January 1977. Directed the Commodity Model Maintenance Project (a joint effort with Charles River Associates, Inc.). This project involved the development of econometric models of the world markets for nonferrous mineral commodities. These models were used to produce five-year projections of demand, supply, and price, and to evaluate the effects of alternative General Services Administration commodity disposal patterns on these commodity markets. Over a four-year period, twelve markets were analyzed: Cobalt, Copper, Chromite, Lead, Manganese, Mercury, Molybdenum, Platinum-Palladium, Rubber, Tin, Tungsten, and Zinc.
Developed a regional econometric model of Luzerne County, Pennsylvania, to evaluate the effects of Hurricane Agnes on this area.
Developed a large model of the U.S. auto industry based on time-series and cross-section data. This model, which was developed for the Transportation Systems Center of the U.S. Department of Transportation, was designed as a tool to investigate the longer-term determinants of the size and composition of the U.S. auto fleet and to provide a tool for the analysis of various potential policy initiatives.
Developed a model based on cross-section data for the National Association of Broadcasters to analyze the effects of increasing the number of imported signals carried via cable systems on the audience for local stations.
Participated in the development of Wharton's timesharing software system. Dr. Schink was involved in the selection of a time-sharing vendor, assembly of the programming staff, specification of the software capabilities, the incorporation of Wharton databases and models in the new software system, the development of documentation and the initial marketing effort.
Participated in the design of the Wharton World Model system.
UNIVERSITY OF PENNSYLVANIA, Philadelphia, PA, Spring 1973. Visiting Lecturer
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NAVIGAN,T ECONOMICS
THE BROOKINGS INSTITUTION, Washington, D.C., June 1969- June 1972. Principal Investigator. Quarterly Model Project Responsible for directing the staff of the model project with guidance from senior advisors (primarily Lawrence R. Klein and Gary Fromm). Specified and estimated the version of the Brookings Model which was used to perform analyses presented at the Conference on Research in Income and Wealth, Harvard University, November 1969.
Constructed a condensed version of the Brookings Model to study the gains and losses in simulation and forecasting accuracy associated with disaggregation of econometric models.
Organized a major conference devoted to a review of econometric model building, the contributions of the Brookings Model project, and the perspective for future developments, held in Washington, D.C. during February 1972.
UNIVERSITY OF MARYLAND, Department of Economics, September 1968- June 1972. Lecturer Taught full-time during the 1968-69 school year and part-time (one course per semester) thereafter.
Courses taught include microeconomic theory, macroeconomic theory, mathematics for economists, and econometrics at both the undergraduate and graduate levels.
MATHEMATICA, Princeton, N.J., October 1967- June 1968. Consultant Worked on the Northeast Corridor Project studying the determinants of travel between city-pairs.
UNIVERSITY OF PENNSYLVANIA, Philadelphia, PA, September 1965 -August 1968. Research Fellow, Economic Research Unit ( Worked for Lawrence R. Klein on the Wharton Quarterly Model Project. Under his direction, reestimated the entire model, developed computer software to solve the model, and mounted the model on a timesharing system.
Worked for Phoebus Dhrymes on several studies. Functioned as a programmer in implementing various distributed lag estimation techniques (search technique and spectral analysis technique) and estimated equations using three-stage least squares for a study of corporate investment, dividend, and borrowing policies.
Worked for Edwin Burmeister and F. Gerard Adams on several projects.
ACTIVITIES AND HONORS Board of Directors, Wharton Econometric Forecasting Associates, 1972-87. William Carey Prize for Best Thesis in Economics, University of Pennsylvania. Ford Foundation Dissertation Grant, 1967. Research Fellowship, Economic Research Unit, University of Pennsylvania. Member, American Economic Association & the Econometric Society.
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NAVIGANT ECONOMICS
PUBLISHED ARTICLES "Short and Long Term Simulations with the Brookings Model" (with Gary Fromm and Lawrence R. Klein), in Bert G. Hickman (ed.) Econometric Models of Cyclical Behavior, New York: Bureau of Economic Research, 1972.
"Aggregation and Econometric Models" (with Gary Fromm), International Economic Review, February 1973.
"A Disaggregated Quarterly Model of U.S. Trade and Capital Flows: Simulations and Tests of Policy Effectiveness" (with Sung Y. Kwack), in Gary Fromm and Lawrence R. Klein (eds.), The Brookings Model: Perspective and Recent Developments, Amsterdam and New York: North-Holland Publishing Co. and American Elsevier Publishing Co., Inc., 1975.
"An Evaluation of the Predictive Abilities of a Large Model: Post-Sample Simulations With the Brookings Model," in Gary Fromm and Lawrence R. Klein (eds.), The Brookings Model: Perspective and Recent Developments, Amsterdam and New York: North-Holland Publishing Company and American Elsevier Publishing Company, Inc., 1975.
"The Brookings Quarterly Model: As An Aid to Longer Term Economic Policy Analysis," International Economic Review, February 1975. Reprinted in Lawrence R. Klein and Edwin Burmeister (eds.) Econometric Model Performance: Comparative Simulation Studies of the U.S. Economy, Philadelphia: University of Pennsylvania Press, 1976.
"An Overview of Econometric Model Building In And Of the U.S.A.: Subnational Macro Econometric Modeling," published in Proceedings of the NSF-CNRS Conference on Macroeconometric Models and Economic Forecasting, Universite de Paris, X-Naterre, November 22-26, 1976.
"The International Tin Agreement: A Reassessment" (with Gordon W. Smith), Economic Journal, December 1976, Reprinted in United Malaysia Bank Corporation Economic Review, Vol. 13, No.2, 1977.
"The Practice of Macroeconometric Model Building and Its Rationale," (with E.P. Howrey, L.R. Klein, and M.D. McCarthy), published in Large-Scale Macroeconometric Models, Amsterdam, New York, and Oxford: North-Holland Publishing Company, 1981, pp. 19-58.
"Application of the Fama-French Model to Utility Stocks," (with Richard S. Bower), Financial Markets, Institutions & Instruments 3 (August 1994), pp. 74-96.
"Economic Literature On Price Discrimination And It's Application to the Uniform Pricing of Gasoline," (with James Langenfeld and Wenqing Li), International Journal of the Economics of Business, Volume 10, Number 2, July 2003, pp. 179-193.
"Simulation With Large Econometric Models: The Quest for A Solution," published in Journal of Economic and Social Measurement, Vol. 29, Numbers 1-3, lOS Press, Amsterdam, Washington, D.C., Tokyo, August 2004, pp. 135-143.
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NAVIGANT ECONOMICS
RESEARCH REPORTS, CONFERENCE PRESENTATIONS AND TESTIMONY "Estimation of Forecast Error in a Dynamic and/or Non-Linear Econometric Model," presented at the Econometric Society Meetings, Evanston, IL, December 1968.
"Simulation with Large Econometric Models," presented at the ACM Summer Meetings, Denver, CO, June 1970.
Nonferrous Mineral Commodity studies prepared for the Office of Stockpile Disposal of the General Services Administration Oointly with various staff members at Charles River Associates).
Forecasts and Analysis of the Molybdenum Market, 12/72 Forecasts and Analysis of the Mercury Market, 3/73 Forecasts and Analysis of the Lead Market, 6/73 Forecasts and Analysis of the Zinc Market, 7/73 Forecasts and Analysis of the Cobalt Market, 3/74 Forecasts and Analysis of the Copper Market, 5/74 Forecasts and Analysis of the Tungsten Market, 6/74 Forecasts and Analysis of the Lead Market, 5/75 Forecasts and Analysis of the Tungsten Market, 9/75 Forecasts and Analysis of the Manganese Market, 1 0/75 Forecasts and Analysis of the Mercury Market, 11/75 Forecasts and Analysis of the Manganese Market, 11/76
An Econometric Model of Luzerne County, prepared for the Department of Commerce, Commonwealth of Pennsylvania, June 1974.
An Analysis of the Automobile Market: Modeling the Long-Run Determinants, 3 Volumes (with Colin ... ( Loxley), prepared for the U.S. Department of Transportation, Transportation Systems Center, Cambridge, MA, February 1977.
"Financing the Energy Program" (with Lawrence R. Klein and Richard M. Young), testimony before the Subcommittee on Administration of the Internal Revenue Code of the Committee on Finance, U.S. Senate, June 6, 1977.
"The Oil Equalization Tax" (with William Finan), testimony before the Committee on Energy and Natural Resources, U.S. Senate, September 16, 1977.
The Impacts of Cable TV on Local Station Audience (with Sheela Thanawala), prepared for the National Association of Broadcasters, 1771 N Street, N.W., Washington, D.C. 20036, March 1978.
Analysis of the Macroeconomic Impacts of the Proposed NHTSA Passenger Car MPG Standards, prepared for the Chase Manhattan Bank, N.A., 1 Chase Manhattan Plaza, New York, N.Y. 10015, January 1979.
"U.S. Economic Prospects for the Next Ten Years," The Wharton Magazine, Winter 1979.
Simulation Study of Eight Petroleum Supply Disruption Scenarios, prepared for the Macroeconomic Analysis Division of the Energy Information Administration, U.S. Department of Energy, April 1979.
"Input-Output in the Context of the Wharton Annual Model "(with Gene D. Guill and Yacov Shainin), Wharton Annual Model Working Paper Number 6, April 1978. Presented at the Seventh International Conference on Input-Output Techniques, lnnsbruck, Austria, April1979.
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NAVIGANT ( ECONOMICS "Optimal Control and Macroeconomic Models," a paper prepared as part of a study entitled Mexico--Economic Policy Analysis--1978/1983: A Macroeconometric Model of Mexico and Control Theory Applications, by Oscar Adolfo Rufatt, under a grant from the Inter-American Development Bank, May 1979.
"Integration of Neoclassical Production Function Theory and Input-Output Matrices" (with Gene D. Guill and Yacov Shainin), presented at a Seminar on Production Functions at the U.S. Department of Energy, May 21, 1979.
The Wharton Annual Energy Model: Development and Simulation Results (with William Finan), prepared for the Electric Power Research Institute, 3412 Hillview Avenue, Palo Alto, California 93404, EPRI EA-1115, Project 440-1, July 1979.
A Historical Analysis of the Impacts of Indexed Depreciation (with Sheila Bassett and Yacov Shainin), prepared for the Sun Company, Inc., Radnor, PA, October 1979.
"A Macroeconomic Analysis of the Carter Energy Plan," presented at the Conference on Energy Prices, Inflation, and Economic Activity, Massachusetts Institute of Technology, Cambridge, ..MA, November 9, 1979.
The Macroeconomic Effects of Oil Supply Curtailments in 1985 and 1990 (with William Finan), prepared for the U.S. Department of Energy, December 1979.
A Macroeconometric Model to Allow Energy Policy Analysis of Changing Fuel Specific Prices on Production Capabilities (with Gene D. Guill and Yacov Shainin), prepared for the Macroeconomic Analysis Division of the Energy Information Administration, U.S. Department of Energy, April1980.
The Development of an Analytical Procedure for the Evaluation of the Effect on Energy Price Increases on Non-Energy Commodities (with Gene D. Guill and Yacov Shainin), prepared for the Macroeconomic Analysis Division of the Energy Information Administration, U.S. Department of Energy, April 1980.
Impact of Local Content Legislation On U.S. and World Economies, (with Colin Loxley), prepared for the Japan Automobile Manufacturers Association, Inc., July 1983.
Macroeconomic Analysis Of a Program For the Redevelopment of Troubled U.S. Industries, prepared for The Sun Company, Radnor, PA, October 1983.
Impact of the FCC Access Charge Plan On the U.S. Economy, (with Vijaya G. Duggal and John Green), prepared for the American Telephone & Telegraph Company, November 1983.
Brief Macroeconomic Analysis of S.1435: The Housing Opportunity and Mortgage Equity Act of 1983 (Home Act), prepared for the National Association of Home Builders of the United States, Washington, DC, December 1983.
Testimony on Electric Power Demand in the PECO Service Area before the Pennsylvania Public Utility Commission, January 1985.
Analysis of the Impact of the Treasury Department's Initial 1985 Tax Plan on the Agricultural Sector of the Economy, prepared for the Granada Management Corporation, March 1985.
Impact of a Ban on the Use of Alachlor, prepared for the Monsanto Agricultural Products Company (with John M. Urbanchuk), March 1985. c \.,,
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NAVIGAN ECONOMICS
Rebuttal Testimony on Projections of Electric Power Demand in the PECO Service Area, Pennsylvania "'-·- Public Utility Commission, April 1985.
Testimony on the issue of the Economic Impact of the Gibbons Bill on the United States Economy before the Subcommittee on Trade of the Committee on Ways and Means, Washington, D.C., June 1985.
Assessment of the Likely Impacts of The President's Tax Proposals on Rental Housing Markets, prepared for the Tax Fairness for Housing Coalition (with Art Doud and William C. Apgar and H. James Brown of the Joint Center for Housing Studies of M.I.T. and Harvard University), July 1985.
Economy-Wide Impacts of Agricultural Sector Loan Losses, prepared for the Food and Agricultural Policy Research Institute (FAPRI) (with John M. Urbanchuk), July 1985.
Evaluation of the Impacts of the President's Tax Proposals on the Real Estate Industry and the Economy, prepared for the Real Estate Securities and Syndication Institute, October 1985.
An Analysis of the Macroeconomic Impacts of Tariff Induced Increases in U.S. Softwood Lumber Prices, prepared for the Council of Forest Industries, October 1985.
Testimony on The Economic Impacts of Implementing the Tax Reform Act of 1985 (H.R. 3838) before the Senate Committee on Finance, Washington, D.C., January 1986.
Rebuttal and Sur-Surrebuttal Testimony for PECO on the Impact of a Rate Increase on the Philadelphia Economy before the Pennsylvania Public Utility Commission, February-March 1986.
~ The Income of Organized Crime, prepared for the President's Commission on Organized Crime, March 1986. ( ( National Consequences of Exporting Alaska North Slope Crude Oil, prepared for the Exxon Shipping Company, May 1986.
The Macroeconomic Costs of Limiting the Deductibility of Advertising Expenses, prepared for the American Association of Advertising Agencies, Inc., the American Advertising Federation, and the Association of National Advertisers, Inc., June 1986.
Pricing Telecommunications Services: The Impact on the U.S. Economy of Subscriber Line Charges, prepared for the American Telephone & Telegraph Company, August 1986.
GE Vehicle Price Forecasting System, prepared for the GE Credit Auto Leasing Company (with John A. Del Roccili), September 1986.
Testimony on Home Air Conditioning Saturation Rates and its Effect on Peak Electricity Demand before the Indiana Public Service Commission, December 1986.
Effects on the New York Economy of Regulation of its Telecommunications Market, prepared for the American Telephone & Telegraph Company, January 1987.
Testimony on the Economic Effects of Relocating an Automobile Dealership in Canonsburg, Pennsylvania, before the Pennsylvania Board of Motor Vehicle Dealer Licensing, January 1987.
An Evaluation of the FTC's Analysis of the Effects of RMA Laws on Auto Markets, prepared for National Automobile Dealers Association, January 1987.
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NAVIGANT ECONOMICS
Deregulating Telecommunications: Economic Impacts on New York State, prepared for the New York Telephone Company, February 1987.
Testimony on the Determination of an Appropriate Discount Rate to Apply to the Expected Income of a Real Estate Syndication before the American Arbitration Association in New York, March 1987.
Testimony on the Economic Effects of Relocating an Automobile Dealership in Red Lion, Pennsylvania before the Pennsylvania Board of Motor Vehicle Dealer Licensing, March 1987.
Testimony on the Economic Effects of Allowing PHH, A Retail Auto Broker, to Operate in Pennsylvania before the Pennsylvania Board of Motor Vehicle Dealer Licensing, August 1987.
The Impact on the U.S. Economy of Regulatory Changes in the Interstate Long-Distance Telecommunications Market, prepared for the American Telephone and Telegraph Company, October 1987.
Testimony on the Economic Effects of Relocating an Automobile Dealership in Minneapolis-St. Paul, Minnesota before the Minnesota Court of Common Pleas, October 1987.
Target Industry Study for Iron and Washington Counties, Utah (with Kate Rodenrys), prepared for Pacific Power and Light Company, March 19, 1988.
Testimony on the Evaluation of Dealer Performance Related to Termination of the Dealership in Erie, Pennsylvania before the Pennsylvania Board of Motor Vehicle Licensing, October 1988.
( ~··· Testimony on the Competitiveness in the Markets Served by Buckeye Pipe Line Company, L.P. in Oil Product Transportation, Phase I (Docket No. IS87-14-000), before the Federal Energy Regulatory '--·· Commission, Washington, D.C., April 1989.
Prepared Direct Testimony (Draft) on the Competitiveness of Markets Served by Sun Pipeline Company in Oil Product and Crude Oil Transportation, Document Supplied to General Counsel, June 1989.
Analysis of Ohio and Indiana Markets for Refined Petroleum Product Transportation, Prepared for Buckeye Pipe Line Company, L.P., June 1989.
Analysis of Eastern Product Systems Market for Refined Petroleum Product Transportation, Prepared for Sun Pipe Line Company, July 1989.
Testimony on the Effects of Adding a New Buick Dealership in San Diego, CA, Before the California New Motor Vehicle Board, November 1989.
Deposition on the Effects of Adding a New Cadillac Dealership in Los Angeles, CA, Related to Proceedings Before the California New Motor Vehicle Board, 1989.
Deposition on the Effects of Terminating a Ford Dealership in Youngstown, OH, Related to Proceedings Before Ohio New Motor Vehicle Commission, 1989.
Rural/Urban Cross Subsidies in the U.S. Long Distance Markets (with Jerry Langin-Hooper), prepared for Bell Canada, 1990.
Deposition on the Effects of Adding a New Toyota Dealership in Los Angeles, CA, Related to Proceedings Before the California New Motor Vehicle Board, 1990.
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NAVIGANT ECONOMICS
Testimony on the Effects of Terminating a Jaguar Dealership in Orange County, CA, Before the California New Motor Vehicle Board, March 1990.
Testimony on the Effects of Adding a New Ford Dealership in Beverly Hills, CA, Before the California New MotorVehicle Board, March-April1990.
Analysis of Competition in Markets Served by Atlantic Pipeline Company, Prepared for Sun/Atlantic Pipe Line Company, April 1990.
Developed an Econometric Model for Forecasting and Analyzing U.S. Auto and Light Truck Demand for a Consortium of Japanese AutoMakers, May 1990.
Testimony on the Effects of Adding a New Toyota Dealership in Tulsa, OK, Before the Oklahoma Motor Vehicle Dealer Commission, July 1990.
Prepared Analysis and Wrote Testimony Related to the Competition Faced by Amoco Pipe Line Company in Crude Oil Transportation, FERC Docket No. IS90-30-000, August 31, 1990.
Testimony on the Effects of Adding a New Toyota Dealership in Pittsburgh, PA, Before the Pennsylvania Board of Motor Vehicle Licensing, October 1990.
Presentation on the Effects of Adding a New Ford Dealership in Kansas City, Before the Ford Dealer Policy Board, October 1990.
The Effects of Long-Distance Competition on Small and Rural Jurisdictions in the United States with Comparisons to Newfoundland (with Jerry Langin-Hooper), prepared for Newfoundland Telephone, November 1990. ( ( Deposition on the Effects of Adding a New Honda Dealership in Minneapolis-St. Paul, Related to Proceedings in Minnesota State Court, January 1991.
Testimony on Calculating the Cost of Capital Using the CAPM Model, A Barometer Group of Companies, and a Risk Premium Approach Rebutting Testimony by a Commission Staff Witness, prepared for Consumers Power Company and Presented Before the Michigan Public Service Company, Case No. U- 9346, January 15, 1991.
Prepared Analysis and Wrote Testimony Related to the Competition Faced by ARCO Pipe Line Company in Oil Product Transportation, FERC Docket No. IS90-34-000, February 1, 1991.
Prepared Analysis and Wrote Testimony Related to an Evaluation of Georgia Power's Proposed Integrated Resource Plan Including Demand-Side Options Related to General Regulatory Treatment and Specific Programs for Interruptible Service Tariffs, High Efficiency Lighting, and Residential Demand-Side Initiatives, Docket No. 3979-U, Georgia Public Service Commission, April-May, 1991.
Testimony on the Competitiveness of Markets Served by Williams Pipe Line Company in Oil Product Transportation, FERC Docket No. IS90-21-000, June 1991.
Prepared a Study on the Design of a Residential Time-of-Use Experiment for Delmarva Power and Light, Wilmington, Delaware, June 10, 1991.
Testimony Presented Before the Canadian Radio-Television and Telecommunications Commission, Regarding Unital's Application for Interconnection with Bell Canada, et. al. June 25, 1991.
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N!\VIGANT ECONOMICS
Testimony on Evaluating Ratemaking Alternatives and Performance Incentives Including Revenue Decoupling (ERAM) to Encourage DSM by Electric Utilities, prepared for Orange &. Rockland for presentation to the New York State Public Service Commission Staff, Case 89-E-176, July 18, 1991.
Testimony presented before the New York State Public Service Commission in the Matter of the Revision of Rates, prepared for Orange and Rockland Utilities, Inc. Natural Gas Operations, January 1992.
Macroeconomic and Fiscal Effects of the Luxury Tax on High-Line Cars, prepared for the Federation Against Inequitable and Regressive Taxation (FAIRTAX), February 1992.
Reply Comments on Behalf of Southwestern Bell Telephone Company, prepared for Southwestern Bell Telephone Company for presentation to the Arkansas Public Service Commission, March 26, 1992.
Testimony on the Differential Rate of Return Risk Faced by GTEC's Equity Investors, prepared for GTE California for presentation to the Public Utilities Commission of the State of California, May 1, 1992.
Proposal to Implement the Fama-French Multifactor Approach to Estimating the Cost of Equity Capital for the New York Energy Utilities, submitted to the New York Energy Utilities, June 24, 1992.
Dealing with Allegations of Market Power, presentation to The Pipeline Economics and Management Seminar, The Transportation Center, Northwestern University, November 4, 1992.
Economic analysis and exhibits prepared for Boulevard Ford, Courtesy Ford and Naughton Ford, Denver, Colorado, December 1992.
Summary of Observations and Findings Relative to the Establishment of a Chevrolet Dealership in Glendora, California, January 1993.
Testimony on Cost of Capital presented before the New York State Public Service Commission, prepared for Orange and Rockland Utilities, Inc. (Electric), January 1993.
Application of the Fama-French Model to Utility Stocks (with Richard S. Bower), presented in Proceeding on Motion of the Commission to Consider Financial Regulatory Policies for New York State Utilities (State of New York Department of Public Service Case 91-M-0509), February 1993.
Evaluation of Alternative Price Cap Indices for the Lower 48 Oil Pipeline Industry, in "Comments of the Buckeye Pipe Line Company, L.P. on Commission Staff Proposal" before the Federal Energy Regulatory Commission in Docket No. RM93-11-000 Provisions to Oil Pipeline Regulations Pursuant to the Energy Policy Act of 1992, May 3, 1993.
Study measuring the value of a company providing mental health care insurance in a stock fraud case, prepared for Cole, Milstein, June 1993.
Rebuttal Testimony on Cost of Capital presented before the New York State Public Service Commission, prepared for Orange and Rockland Utilities, Inc. (Electric), June 1993.
A Fairness 'Index' Model to Project Costs and Prices for PPL and UPL Operating as Separate Entities, prepared for PacifiCorp, June 24, 1993.
Summary of Observations and Findings Relative to the Proposed Establishment of a Ford Dealership in Cordova, Tennessee, July 1993.
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N)\VIGANT ECONOMICS
Affidavit before the Federal Communications Commission in the Matter of Implementation of Sections of the Cable Television Consumer Protection and Competition Act of 1992 Rates Regulation (MM Docket 92-266), concerning Commission computed benchmark rates for cable systems, prepared for Dow, Lohnes & Albertson, July 2, 1993.
Economic Analysis and Exhibits prepared for Tirapelli Ford, Joliet, Illinois, August 1993.
Impact for the California Economy of an Exemption for the Manufacturing Sector from the 6 Percent Sales Tax on Machinery and Equipment Spending, prepared for Southern California Edison Company, August 1993.
Testimony presented before the New York State Public Service Commission in the Matter of the Revision of Rates (Case 93-G-0756), prepared for National Fuel Gas Distribution Corporation (New York Division), August 1993.
Rate of Return Recommendations for the U.S. Cable Television Industry (with Frank J. Hanley), presented to the Federal Communications Commission in Implementation of Sections of the Cable Television Consumer Protection and Competition Act of 1992 (MM Docket No. 93-215), prepared for Dow, Lohnes & Albertson, August 25, 1993.
White Paper on Recommended Regulation for the U.S .. Cable Television Industry (with Joseph F. Brennan and Frank J. Hanley), presented to the Federal Communications Commission in Implementation of Sections of the Cable Television Consumer Protection and Competition Act of 1992 (MM Docket No. 93-215) as part of Comments of Cable Operators and Associations, prepared for Cole, Raywid & Braverman, August 25, 1993.
Affidavit before the Federal Communications Commission in the Matter of Implementation of Sections of ( the Cable Television Consumer Protection and Competition Act of 1992 Rates Regulation (MM Docket 92-215), reviewing the Comments of Dr. James H. Vander Weide, prepared for Dow, Lohnes & Albertson, September 13, 1993.
Implementing Indexed Rate Increases: Grandfathered Pipelines Versus Those not Grandfathered, presentation to Oil Pipeline Ratemaking Strategies for the 90's: Impact of Anticipated FERC NOPR, September 29, 1993.
How to Qualify for Market-Based Rates, presentation to Oil Pipeline Ratemaking Strategies for the 90's: Impact of Anticipated FERC NOPR, September 30, 1993.
Rebuttal Verified Statement presented before the Interstate Commerce Commission in Canadian Pacific Limited--Abandonment--Line Between Skinner and Vanceboro, Maine (Docket No. AB-213 (Sub-No. 4)), prepared for Canadian Pacific Limited, October 4, 1993.
Rebuttal Testimony on Cost of Capital presented before the New York Public Service Commission in the Matter of the Revision of Rates (Case 93-G-0756), prepared for National Fuel Gas Distribution Corporation (New York Division), January 1994.
Direct Testimony presented before the Federal Energy Regulatory Commission in Notice of Rate Change, Pacific Gas Transmission Company (Docket No. RP94-149-000) concerning Cost Rate for Common Equity, prepared for Pacific Gas Transmission Company, February 28, 1994.
Prepared Testimony on the Value of a Process that Benefited from a Gravity Bank, Whitehall Products Corp. vs. Golden et al., Civil No. 900905614CV, State of Utah, Case Settled, 1993-1994.
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N!\VIGf\NT c ECONOMICS Competition and Stranded Cost Recovery in the Electricity Sector, with Pablo T. Spiller and Daniel F. Spulber, part of Commonwealth Edison comments in Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, FERC Docket No. RM94-7-000, December 9, 1994.
Direct Testimony presented before the Federal Energy Regulatory Commission on the justness and reasonableness of the rates of Williams Pipe Line Company in Oil Product Transportation, FERC Docket No. IS90-21-000 (Phase II), January 23, 1995.
Rebuttal Testimony presented before the Federal Energy Regulatory Commission in Notice of Rate Change, Pacific Gas Transmission Company (Docket No. RP94-149-000) concerning Cost Rate for Common Equity, prepared for Pacific Gas Transmission Company, February 24, 1995.
Cross Examination before the Federal Energy Regulatory Commission on the Cost of Common Equity for Pacific Gas Transmission Company, FERC Docket No. RP94-149-000, April19 and 24, 1995.
An Assessment of Whether Market-Based Rates Are Appropriate For The Secondary Gas Pipeline Capacity Market, prepared for Associated Gas Distributors, April 25, 1995.
Implementing Indexed Rate Increases, presentation at Executive Enterprises Conference On: Oil Pipeline Ratemaking Strategies for the 90's: The Impact of Final Rule 561, June 8-9, 1995.
Supplemental Direct Testimony presented before the Federal Energy Regulatory Commission on the justness and reasonableness of the rates of Williams Pipe Line Company in Oil Product Transportation, FERC Docket No. IS90-21-000 (Phase II), July 21, 1995.
Submitted Statements in Support of Colonial Pipeline's Application to Charge Market-Based Rates, FERC Docket OR95-9-000, July 21, 1995.
Answering Testimony presented before the Federal Energy Regulatory Commission on the justness and reasonableness of the rates of Williams Pipe Line Company in Oil Product Transportation, FERC Docket No. IS90-21-000 (Phase II), October 26, 1995.
Cross-Examination before the Federal Energy Regulatory Commission on the justness and reasonableness of the rates of Williams Pipe Line Company in Oil Product Transportation, FERC Docket No. IS90-21-000 (Phase II), January 4-5, 1996.
Rebuttal Testimony presented before the Copyright Arbitration Royalty Panel, U.S. Copyright Office In the Matter of 1990-1992 Cable Royalty Distribution Proceeding, Docket No. 94-3 CARP-CD90-92, February 15,1996.
Cross Examination before the Copyright Arbitration Royalty Panel, U.S. Copyright Office In the Matter of 1990-1992 Cable Royalty Distribution Proceeding, Docket No. 94-3 CARP-CD90-92, March 12, 1996.
Analysis of the Effects of the Securities Litigation Initiative on the California Economy, a study prepared for the Accountants' Coalition (Arthur Andersen, L.L.P., Coopers & Lybrand, L.L.P., Deloitte & Touche, L.L.P., Ernst & Young, L.L.P., KMPG Peat Marwick, L.L.P, and Price Waterhouse, L.L.P.), May 28, 1996.
Submitted Direct Testimony in Support of Colonial Pipeline's Application to Charge Market-Based Rates, FERC Docket No. OR95-9-000, July 2, 1996.
Prepared and Submitted an Evaluation of Economic Damages in the Case of Pride Companies, L.P. v. United States, United States Court of Federal Claims No. 95-597C, September 23, 1996.
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NAVIGANT ECONOMICS
Testified and was Cross-Examined Regarding Economic Damages in the Case of Pride Companies v. United States, United States Court of Federal Claims, No. 95-597C, September 30 and October 1, 1996.
Prepared Analysis of the Extent of Competition in the Residential and Commercial Markets and the Effect of the Proposed Merger of Houston Industries and NorAm on that Competition, October-December, 1996.
Prepared An Evaluation of the Agency's Assessment of GEC's Contract Risk Based on Its Estimate of GEC Profits, April 4, 1997.
Prepared a Report on the Effect of the Marathon/Ashland Joint Venture on Competition, October, 1997.
Prepared a study of the Impact of Taxes on Washington Motor Vehicles Sales, October 9, 1997.
Prepared Evaluation of Damages Incurred By Tricord Systems, Inc. Shareholders, October 27, 1997.
Prepared a report on the Effect of a Purchase of a Gas Plant on Competition for Western Gas Resources, February 1998.
Prepared a Report on the Effect of the Merger of Williams and MAPCO, February 1998.
Prepared Statements Supporting Application of Longhorn Partners Pipeline, L.P., For Authority to Charge Market-Based Rates, FERC Docket No. OR98-12-000, March 19, 1998.
Prepared Evaluation of Economic Damages in the Case of Barrett Refining Corporation v. The United States, April 1, 1998.
Prepared An Analysis of the Damages to Silver Spring Auto City, Inc., April 9, 1998.
Prepared a Report on the Effect of the Sale of a Natural Gas Pipeline System on Competition for Transok, May 1998.
Prepared a Report on the Effect of the Proposed Merger of Holly and Giant Industries on Competition, July 1998.
Prepared Analysis of the Impacts of the Proposed Heard Chevrolet Relocation, September 11, 1998.
Prepared Statements Supporting Application of Explorer Pipeline Company for Authority to Charge Market-Based Rates before the Federal Energy Regulatory Commission, FERC Docket No. OR99-1-000, October 14, 1998.
Prepared Supplemental Testimony for Explorer Pipeline Company before the Federal Energy Regulatory Commission, FERC Docket No. OR99-1-000, February 19, 1999.
Prepared Statements Supporting Application of Colonial Pipeline Company for Authority to Charge Market-Based Rates before the Federal Energy Regulatory Commission, FERC Docket No. OR99-5-000, March 26, 1999.
Prepared Statements Supporting Application of TE Products Pipeline Company, L.P. for Authority to Charge Market-Based Rates before the Federal Energy Regulatory Commission, FERC Docket No. OR99-6-000, May 11, 1999.
Prepared Statements Supporting Application of Wolverine Pipe Line Company for Authority to Charge Market-Based Rates before the Federal Energy Regulatory Commission, FERC Docket No. OR99-15- 000, June 14, 1999.
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Nt\VIGANT ( ECONOMICS
Prepared Rebuttal Testimony for Potomac Electric Power Company on the Investigation into Electric Services, Market Competition and Regulatory Policies before the Public Service Commission of the District of Columbia, Formal Case No. 945, July 2, 1999.
Evaluating the Implications of Consolidating All the Dealerships of a Given Make or Manufacturer In a Given Area With Manufacturer Participation, prepared for National Automobile Dealers Association, August 1999.
Prepared Statements Supporting Application of Colonial Pipeline Company for Authority to Charge Market-Based Rates before the Federal Energy Regulatory Commission, FERC Docket No. OR00-3-000, March 16, 2000.
Prepared Statements Supporting Application of Chevron Pipe Line Company for Authority to Charge Market-Based Rates before the Federal Energy Regulatory Commission, FERC Docket No. OR00-6-000, June 13, 2000.
Prepared an economic analysis of BP Amoco's Acquisition of GATX's Interest in the Olympic Pipe Line Company, September 2000.
Provided expert advice to law firm of Sidley & Austin in Five-Year Review of Oil Pipeline Pricing Index by the Federal Energy Regulatory Commission, FERC Docket No. RM00-11-00, October and November 2000.
Prepared Affidavit in TE Products Pipeline Company, L.P. Application for Authority to Charge Market Based Rates before the Federal Energy Regulatory Commission, FERC Docket No. OR99-6-000, November 20, 2000.
Prepared Direct Testimony in Wolverine Pipe Line Company Application for Authority to Charge Market Based Rates before the Federal Energy Regulatory Commission, FERC Docket No. OR99-15-000, December 12, 2000.
Prepared Affidavit in Chevron Pipe Line Company Application for Authority to Charge Market-Based Rates before the Federal Energy Regulatory Commission, FERC Docket No. OR00-6-000, January 10, 2001.
Prepared Cost of Capital Testimony Supporting TransCanada Pipelines Limited 2001 and 2002 Fair Return Application before the National Energy Board of Canada, June 6, 2001.
Preparation of a study of the California Energy Crisis and Its Economic Effects for Fannie Mae, September 17, 2001.
Testimony presented before the Copyright Arbitration Royalty Panel, U.S. Copyright Office In the Matter of Digital Performance Right in Sound Recordings and Ephemeral Recordings, Docket No. 2000-9, CARP DTRA 1& 2, October 4, 2001.
Supplemental Report on Cost of Capital Supporting TransCanada Pipelines Limited 2001 and 2002 Fair Return Application before the National Energy Board of Canada, November 2001.
Prepared Direct Testimony on Cost of Capital and Evidence on Behalf of Olympic Pipe Line Company, FERC Docket No. IS01-441-000, December 13,2001.
Prepared Direct Testimony on Cost of Capital and Evidence on Behalf of Olympic Pipe Line Company, ( Washington Utilities and Transportation Commission, Docket No. T0011472, December 2001.
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NAVIGANT ECONOMICS
Written Reply Evidence on Cost of Capital Supporting TransCanada Pipelines Limited 2001 and 2002 Fair Return Application before the National Energy Board of Canada, February 2002.
The Economic Contribution of the U.S. Commercial Shipbuilding Industry, prepared for Shipbuilders Council of America, April 2002.
Presented Testimony before the Mississippi Motor Vehicle Commission supporting Mississippi Automobile Dealers' Association, April 2002.
Prepared Affidavit in Support of Rocky Mountain Pipeline System LLC before the Federal Energy Regulatory Commission, FERC Docket No. OR02-6-000, May 17, 2002.
Testified before the Washington Utilities and Transportation Commission on Cost of Capital and Capital Structure Supporting Olympic Pipe Line Company, Inc. in Washington Utility and Transportation Commission, v. Olympic Pipe Line Company, Inc., Docket No. T0011472, June 2002.
Prepared Rebuttal Testimony and Exhibits on Cost of Capital and Capital Structure Supporting Olympic Pipe Line Company before the Federal Energy Regulatory Commission, FERC Docket No. IS01-441-000, June 10, 2002.
Prepared Rebuttal Testimony on Cost of Capital and Capital Structure Supporting Olympic Pipe Line Company, Inc. in Washington Utility and Transportation Commission, v. Olympic Pipe Line Company, Inc. before the Washington Utilities and Transportation Commission, Docket No. T0011472, June 11, 2002.
Prepared Direct Testimony Supporting Pacific Terminals LLC in Joint Application of Southern California , Edison Company (U 338-E) and Pacific Terminals LLC for Southern California Edison Company to Sell ( Fuel Oil Pipeline Facilities to Pacific Terminals LLC and for Pacific Terminals LLC to Purchase such Fuel Oil Pipeline Facilities and to Operate Them as a Public Utility, Public Utilities Commission of the State of California, Docket A. 02-03-035, June 21, 2002.
Prepared Statements Supporting Application of Rocky Mountain Pipeline System LLC for Authority to Charge Market-Based Rates before the Federal Energy Regulatory Commission, FERC Docket No. OR02-11-000, July 22, 2002.
Prepared Affidavit Supporting Rocky Mountain Pipeline System LLC before the Federal Energy Regulatory Commission, FERC Docket No. OR02-11-000, August 22, 2002.
Prepared report on the Economic Effects of the Proposed Baja California LNG Plants for a major gas pipeline operator, October 2002.
Prepared Declaration on Cost of Capital on Behalf of Olympic Pipe Line Company in Olympic Pipe Line Company v. Washington Utility and Transportation Commission in Superior Court of the State of Washington in and for the County of Thurston, October 24, 2002.
Prepared Affidavit Supporting Rocky Mountain Pipeline System LLC before the Federal Energy Regulatory Commission, FERC Docket No. OR02-11-000, December 13, 2002.
The Economic Impacts on California of the Proposed Mattress Flammability Standard, April17, 2003.
Prepared Rebuttal Testimony Before The Copyright Arbitration Royalty Panel Distribution of 1998 and 1999 Cable Royalty Funds, Docket No. 2001-8 CARP CD 98-99, July 8, 2003.
Advised Retail Distributor of Motor Gasoline Regarding Implications of Refinery Merger, December 2003. ( ·. .__ (
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NAVIGANT ECONOMICS
Prepared Testimony on Cost of Capital on Behalf of Olympic Pipe Line Company before the Federal Energy Regulatory Commission, FERC Docket No. IS03-218-000, July 11, 2003.
Prepared Affidavit on Behalf of BP Pipelines (North America), Inc. in Sinclair Oil Corporation v. BP Pipelines (North America), Inc. before the Federal Energy Regulatory Commission, FERC Docket No. OR02-6-02, August 20, 2003.
Prepared Expert Report on Behalf of Don Rasmussen Company in the Matter of Don Rasmussen Company, Plaintiff v. BMW of North America, LLC and BMW of North America, Inc., Defendants, in the Circuit Court of the State of Oregon for the County of Multnomah, Civil No. CV02-1504 Kl, August 22, 2003.
Prepared Direct Testimony Supporting Application of Shell Pipeline Company LP for the Authority to Charge Market-Based Rates before the Federal Energy Regulatory Commission, FERC Docket No. OR02-10-000, August 29, 2003.
Prepared Damages Report on Behalf of-Yerington Ford, Inc. and William Giles and Linda Giles In the Matter of Yerington Ford, Inc. and William Giles and Linda Giles, Plaintiffs Versus General Motors Acceptance Corporation, Defendant, September 26, 2003.
Prepared Affidavit Supporting Application of Shell Pipeline Company LP for the Authority to Charge Market-Based Rates before the Federal Energy Regulatory Commission, FERC Docket No. OR02-1 0- 000, October 20, 2003.
Testified and was cross-examined on Behalf of Don Rasmussen Company in the Matter of Don Rasmussen Company, Plaintiff v. BMW of North America, LLC and BMW of North America, Inc., Defendants, in the Circuit Court of the State of Oregon for the County of Multnomah, Civil No. CV02-1504 Kl, December 17, 2003.
Prepared Testimony on Behalf of BP Pipelines (North America), Inc. in Sinclair Oil Corporation v. BP Pipelines (North America), Inc. before the Federal Energy Regulatory Commission, FERC Docket No. OR02-6-02, January 9, 2004.
Deposition on Behalf of Yerington Ford, Inc. and William Giles and Linda Giles In the Matter of Yerington Ford, Inc. and William Giles and Linda Giles, Plaintiffs Versus General Motors Acceptance Corporation, Defendant, March 16, 2004.
Prepared Opinion Letter in Debra L. Godsey, et al, vs. Southeast Toyota Distributors, LLC, et al., United States District Court, Middle District of Florida, Tampa Division, Case No. 8:03-CV-0102-T-26MAP, on allegations of product tying in automotive accessories industry, April15, 2004.
Prepared Opinion Letter for Olympic Pipeline regarding Olympic Pipeline Cost of Capital, July 22, 2004.
A Comparison Of The Subsidies Provided By Canadian Governments To The Oil And Ethanol Industries (with William Toms and John M. Urbanchuk) for the Canadian Renewable Fuels Association, October 28, 2004.
Prepared Expert Report in Tractebel Energy Marketing, Inc. v. AEP Power Marketing, Inc., American Electric Power Company, Inc. and Ohio Power Company, United States District Court, Southern District of New York, Case No. 03 Civ 6731 (Hb) (Jcf) and Ohio Power Company and AEP Power Marketing, Inc. v. Tractebel Energy Marketing, Inc., and Tractebel, S.A., Case No. 03 Civ 6770 (Hb) (Jcf), January 13, 2005.
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NA.VIGANT ECONOMICS
Prepared Rebuttal Expert Report in Tractebel Energy Marketing, Inc. v. AEP Power Marketing, Inc., American Electric Power Company, Inc. and Ohio Power Company, United States District Court, Southern District of New York, Case No. 03 Civ 6731 (Hb) (Jcf) and Ohio Power Company and AEP Power Marketing, Inc. v. Tractebel Energy Marketing, Inc., and Tractebel, S.A., Case No. 03 Civ 6770 (Hb) (Jcf), February 3, 2005.
Deposition in Tractebel Energy Marketing, Inc. v. AEP Power Marketing, Inc., American Electric Power Company, Inc. and Ohio Power Company, United States District Court, Southern District of New York, Case No. 03 Civ 6731 (Hb) (Jcf) and Ohio Power Company and AEP Power Marketing, Inc. v. Tractebel Energy Marketing, Inc., and Tractebel, S.A., Case No. 03 Civ 6770 (Hb) (Jcf), February 22, 2005.
Presented testimony regarding Tractebel Energy Marketing, Inc. v. AEP Power Marketing, Inc., American Electric Power Company, Inc. and Ohio Power Company, United States District Court, Southern District of New York, Case No. 03 Civ 6731 (Hb) (Jcf) and Ohio Power Company and AEP Power Marketing, Inc. v. Tractebel Energy Marketing, Inc., and Tractebel, S.A., Case No. 03 Civ 6770 (Hb) (Jcf), March 2005.
Prepared Opinion Letter regarding the Public Interest Implications of Enbridge's Applications for Non Routine Adjustments Related to Spearhead Pipeline and the Mobil Pipe Line Company 20" Reversal Project for Enbridge Pipelines, March 30, 2005.
Submitted Expert Report on Damages in the Matter of the Arbitrations among PG&E Energy Trading - Power, L.P., and Southaven Power, LLC, and Caledonia Generating LLC, and National Energy & Gas Transmission, Inc., September 6, 2005.
Submitted Rebuttal Expert Report on Damages in the Matter of the Arbitrations among PG&E Energy Trading- Power, L.P., and Southaven Power, LLC, and Caledonia Generating LLC, and National Energy ( & Gas Transmission, Inc., October 3, 2005. \ (
Submitted Updated Expert Report on Damages in the Matter of the Arbitrations among PG&E Energy Trading- Power, L.P., and Southaven Power, LLC, and Caledonia Generating LLC, and National Energy & Gas Transmission, Inc., January 11, 2006.
Submitted Surrebuttal Expert Report on Damages in the Matter of the Arbitrations among PG&E Energy Trading - Power, L.P., and Southaven Power, LLC, and National Energy & Gas Transmission, Inc., May 1, 2006.
Submitted Expert Report on Damages in the Continental Resources, Inc. v. Bridger Pipeline, LLC, Butte Pipeline Company, and Eighty-Eight Oil, LLC, in the United States District Court for the District of Montana, Billings Division (CIVIL CV-05-21-BLG-RWA), LLC, June 1, 2006.
Testified before Arbitration Panel in the Matter of the Arbitration between PG&E Energy Trading -Power, L.P., and Southaven Power, LLC, and National Energy & Gas Transmission, Inc., June 26-30, 2006.
Prepared Report "LECG's Proposed Approach for Testing and Enhancing CCC's Valuescope Procedure," for Latham & Watkins LLP on behalf of CCC Information Services, September 29, 2006.
Assisted major energy company in responding to Federal Trade Commission review of a refinery, refined product terminals, and retail gasoline outlets acquisition, 2007.
Prepared testimony on behalf of Reliant Energy Services, Inc. and four individuals, before the US District Court for the Northern District of California, San Francisco Division, Docket no. CR 04-0125 VRW, in the matter of United States of America v. Reliant Energy Services, Inc. et al. in case involving claims of price manipulation and a criminal violation of the Commodity Exchange Act, February 2007.
December 2011 www. nav iganteconomics.com Page 18 of2() 20111202-5190 FERC PDF (Unofficial) 12/2/2011 4:46:13 PM
N/\VIGANT ECONOMICS
Prepared Written Evidence on Behalf of Imperial Oil in The Matter of an Application by Enbridge Pipelines Inc., before the Canadian National Energy Board, Application No. OH-2-2007, July 30, 2007.
Assisted major energy company in responding to Federal Trade Commission investigation into fuel pricing in a U.S. regional market, August 2007.
Prepared Statements Supporting Application of Mobil Pipe Line Company for Authority to Charge Market Based Rates before the Federal Energy Regulatory Commission, FERC Docket No. OR07-21-000, August 24, 2007.
Assisted major energy transportation company in responding to Federal Trade Commission review of asset acquisition, September 2007.
Prepared Report "Economic Analysis of the Proposed CACP Anti-Counterfeiting and Piracy Initiative" for the Coalition Against Counterfeiting and Piracy (CACP) with Laura Tyson and Tapan Munroe, November 2007.
Prep-ared Supplemental Direct Testimony on Behalf of Mobil Pipe Line Company in FERC Docket No. OR07-21-000, the Application of Mobil Pipe Line Company for Authority to Charge Market-Based Rates before the Federal Energy Regulatory Commission, March 5, 2008.
Prepared Rebuttal Testimony on Behalf of Mobil Pipe Line Company in FERC Docket No. OR07-21-000, the Application of Mobil Pipe Line Company for Authority to Charge Market-Based Rates before the Federal Energy Regulatory Commission, September 3, 2008.
Prepared Supplemental Rebuttal Testimony on Behalf of Mobil Pipe Line Company in FERC Docket No. OR07-21-000, the Application of Mobil Pipe Line Company for Authority to Charge Market-Based Rates before the Federal Energy Regulatory Commission, September 29, 2008.
Prepared Supplemental Rebuttal Testimony on Behalf of Mobil Pipe Line Company in FERC Docket No. OR07-21-000, the Application of Mobil Pipe Line Company for Authority to Charge Market-Based Rates before the Federal Energy Regulatory Commission, February 6, 2008.
Testified and was Cross-Examined Regarding the Application of Mobil Pipe Line Company for Authority to Charge Market-Based Rates before the Federal Energy Regulatory Commission, February 20 and 23, 2009.
Prepared Rebuttal Testimony in SFPP, L.P. in FERC Docket No. IS08-390-002 before the Federal Energy Regulatory Commission, March 27, 2009.
Testified and was Cross-Examined Regarding SFPP, L.P., FERC Docket No. IS08-390-002 before the Federal Energy Regulatory Commission, June 2009.
Prepared Statements Supporting Application of Magellan Pipeline Company, L.P. for Authorization to Charge Market-Based Rates before the Federal Energy Regulatory Commission (South System), FERC Docket No. OR09-09-000, June 2, 2009.
Prepared Statements Supporting Application of Magellan Pipeline Company, L.P. for Authorization to Charge Market-Based Rates before the Federal Energy Regulatory Commission (Mountain System), FERC Docket No. OR10-06-000, January 15,2010.
Prepared "Analysis of the Impacts of S.1620 On New Vehicle Fleet MPG and C02 Emissions" for the Auto Alliance, January 2010. (
December 2011 V.fW\V. nav iganteconornics. com Page 19of20 20111202-5190 FERC PDF (Unofficial) 12/2/2011 4:46:13 PM
NAVIGANT !:CONOMICS
Prepared Supplemental Prepared Direct Testimony on Behalf of Magellan Pipeline Company, L.P. in FERC Docket No. OR10-06-000, the Application of Magellan Pipeline Company, L.P. for Authorization to Charge Market-Based Rates before the Federal Energy Regulatory Commission (Mountain System), April 15, 2010.
Prepared Supplemental Direct Testimony on Behalf of Magellan Pipeline Company, L.P. in FERC Docket No. OR10-06-000, the Application of Magellan Pipeline Company, L.P. for Authorization to Charge Market-Based Rates before the Federal Energy Regulatory Commission (Mountain System), October 15, 2010.
Prepared Expert Report in Opposition to Class Certification in Elaine Fesmire vs. Progressive Max Insurance; Progressive Casualty Insurance Company; Progressive Direct Insurance Company; Progressive Company, Case No.: 3:10-cv-05291-JLR in the U.S. Court In and For the Western District of Washington at Seattle, December 10, 2010.
Deposition in Elaine Fesmire vs. Progressive Max Insurance; Progressive Casualty Insurance Company; Progressive Direct Insurance Company; Progressive Company, Case No.: 3:10-cv-05291-JLR in the U.S. Court In and For the Western District of Washington at Seattle, January 4, 2011.
Prepared Statements Supporting Application of Enterprise TE Products Pipeline Company, LLC. for Authorization to Charge Market-Based Rates before the Federal Energy Regulatory Commission, FERC Docket No. OR11-06-000, March 1, 2011. ·
Prepared Expert Report for Tesoro Corporation and Tesoro Refining and Marketing Company in United States District Court, Southern District of New York, In re: Methyl Tertiary Butyl Ether ("MTBE") Products Liability Litigation, MDL No. 1358, Master File No. 1:00-1898 (SAS), City of Merced Redevelopment (/, Agency (Plaintiff) v. Exxon Mobil Corp. et al (Defendants), Case No.: 08-CV-06306 (SAS), May 6, 2011.
Prepared Expert Report for Tesoro Corporation and Tesoro Refining and Marketing Company in United States District Court, Southern District of New York, In re: Methyl Tertiary Butyl Ether ("MTBE") Products Liability Litigation, MDL No. 1358, Master File No. 1 :00-CIV-1898 (SAS), Orange County Water District (Plaintiff) v. Unocal Corporation., et al. (Defendants), Case No.: 04-CV-04968 (SAS), May 13, 2011.
Presentation before Third Way Idea Forum "The Next Stimulus? Bringing Corporate Tax Dollars Home to Work for America" on the economic and policy implications of a repatriation tax holiday, June 15, 2011.
Deposition in Methyl Tertiary Butyl Ether ("MTBE") Products Liability Litigation, MDL No. 1358, Master File No. 1:00-1898 (SAS), City of Merced Redevelopment Agency (Plaintiff) v. Exxon Mobil Corp. et al (Defendants), Case No.: 08-CV-06306 (SAS), July 20, 2011.
Deposition in Methyl Tertiary Butyl Ether ("MTBE") Products Liability Litigation, MDL No. 1358, Master File No. 1:00-CIV-1898 (SAS), Orange County Water District (Plaintiff) v. Unocal Corporation., et al. (Defendants), Case No.: 04-CV-04968 (SAS), July 20, 2011.
Prepared Expert Report in Opposition to Class Certification in Mikhail Maryanouskiy vs. American Family Mutual Insurance Company, Case No.: 11-CV-1 06 in the U.S. Court In and For the Western District of Wisconsin, September 16,2010.
Prepared Expert Report for Tesoro Corporation and Tesoro Refining and Marketing Company in United States District Court, Southern District of New York, In re: Methyl Tertiary Butyl Ether ("MTBE") Products Liability Litigation, MDL No. 1358, Master File No. 1:00-1898 (SAS), City of Fresno (Plaintiff) v. Chevron USA, Inc., et al. (Defendants), Case No.: 04-CIV-04793 (SAS), November 18, 2011.
December 2011 www. nav i ganteconornics .com Page 20 of20 20111202-5190 FERC PDF (Unofficial) 12/2/2011 4:46:13 PM
( - DECLARATION '·· District of Columbia ) ) ss City of Washington, DC )
George R. Schink hereby declares under penalty of perjury of the laws ofthe United States that the. foregoing document is true and correct to the best of his knowledge and belief. See28 U.S.C. § 174H.. Executed on this 1st'day of December, 2011. 20111202-5190 FERC PDF (Unofficial) 12/2/2011 4:46:13 PM
UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION
Enterprise Products Partners L.P. ) Docket No. OR12-___ and Enbridge Inc. )
PREPARED DIRECT TESTIMONY OF MARK A. HURLEY
1 Q. Please state your name, occupation and business address.
2 A. My name is Mark A. Hurley. I am the Senior Vice President of Crude Oil and Offshore
3 Pipelines for Enterprise Products Partners L.P. ("Enterprise"). My duties include the
4 management of Seaway Crude Pipeline Company ("Seaway"), which is 50% owned, and
5 operated by affiliates of Enterprise. My business address is 1100 Louisiana A venue, P. 0. ( 6 Box 4324, Houston, Texas 77002.
7
8 Q. Please summarize your professional background.
9 A. I have worked for Enterprise since March 2010. Prior to joining Enterprise, I was the
10 President of Shell Pipeline Company. I have spent my entire career in the energy
11 business, working in various business roles and executive management positions, in areas
12 ranging from refining, marketing, sales, transportation, product supply planning and
13 trading. 20111202-5190 FERC PDF (Unofficial) 12/2/2011 4:46:13 PM
( 1 Q. What is the purpose of your testimony?
2 A. The purpose of my testimony is to support the application of Enterprise and Enbridge Inc.
3 ("Enbridge") for authority to file market-based rates in connection with their proposed
4 reversal of the Seaway pipeline system. My testimony generally describes (1) Seaway's
5 organization, facilities and operations; (2) the proposed reversal of the Seaway pipeline;
6 (3) the competitive factors related to the markets for which authority to file market-based
7 rates is being sought, and (4) the reasons why Enterprise and Enbridge are seeking
8 market-based ratemaking authority. Enterprise and Enbridge have retained Dr. George R.
9 Schink to present the analytical data required by the Commission. Dr. Schink is
10 responsible for the preparation of Statements A through H of the application and has also
11 prepared and submitted testimony that is included with my testimony in Statement I of ( 12 the application. '----' 13
14 Q. Please identify the owners of Seawa,y.
15 A. Seaway is currently owned 50% by Enterprise Seaway, L.P. (a wholly-owned subsidiary
16 ofEnterprise), with the remaining 50% owned by two ConocoPhillips entities, Seagas
17 Pipeline Company and Phillips Gas Pipeline Company, which own 33% and 17% of
18 Seaway, respectively. On November 16,2011, Enbridge announced that it has entered
19 into an agreement to purchase the 50% share of Seaway owned by the ConocoPhillips
20 entities. Enbridge anticipates that the purchase will be completed by the end of 2011.
( "--,_-
-2- 20111202-5190 FERC PDF (Unofficial) 12/2/2011 4:46:13 PM
1 Q. Please describe the facilities and operations of the Seaway pipeline system. (~( 2 A. The Seaway system primarily consists of an approximately 500-mile, 30-inch diameter
3 pipeline that currently provides south-to-north transportation of crude oil from origins on
4 the U.S. Gulf Coast to its destination at Cushing, Oklahoma. Enterprise and Enbridge
5 plan to reverse the flow of crude oil on the Seaway system in order to provide north-to-
6 south service from Cushing to the Gulf Coast. I refer to the new reversed line in this
7 affidavit as the "Reversed Seaway Pipeline." It is anticipated that the Reversed Seaway
8 Pipeline will begin operating in north-to-south service on April1, 2012, with an initial
9 capacity of approximately 150,000 barrels per day depending upon the specific mix of
10 crude oil transported. Following pump additions and modifications anticipated to be
11 completed by early 2013, the capacity ofthe Reversed Seaway Pipeline is expected to be
approximately 375,000 barrels per day, again depending upon the specific mix of crude 12 ( ( 13 oil transported. Initially, the Reversed Seaway Pipeline will have one delivery point at
14 Houston. An additional delivery point at the Beaumont/Port Arthur, Texas area will be
15 added by the end of 2013 or the beginning of 2014. The investment required to reverse
16 the line and construct the additional facilities necessary to bring it up to full capacity is
17 expected to be approximately $300 million. Statement F to this Application includes a
18 map showing the service to be provided by the Reversed Seaway Pipeline. See Statement
19 Fat 1.
( -, \ ___(_
- 3- 20111202-5190 FERC PDF (Unofficial) 12/2/2011 4:46:13 PM
( 1 Q. What type of crude oil will the Reversed Seaway Pipeline move? " 2 A. The Reversed Seaway Pipeline plans to move light, sweet crude oil (i.e., West Texas
3 Intermediate or "WTI"), and heavy, sour Canadian Crude (i.e., Western Canadian Select
4 or "WCS"); however, it will be able to move any type of crude oil.
5
6 Q. Does the type of crude oil transported affect the capacity of the Reversed Seaway
7 Pipeline?
8 A. Yes. Heavy crude oil reduces available capacity, since it takes longer to move. If the
9 Reversed Seaway Pipeline were to move only light crude oil, its capacity after post-
10 reversal enhancements are completed would be approximately 375,000 barrels per day.
11 If the Reversed Seaway Pipeline were to move only heavy crude oil, its capacity would ( 12 be approximately 275,000 barrels per day. ~- 13
14 Q. Has the Reversed Seaway Pipeline posted a rate for its proposed north-to-south service?
15 A. No, since the north-to-south service is not expected to begin until April1, 2012, there is
16 currently no posted tariff or rate for that service. If Enterprise and Enbridge obtain
17 market-based ratemaking authority prior to commencement of service on the Reversed
18 Seaway Pipeline, they anticipate that the initial general commodity rate will be set with
19 reference to the market price for transportation at the time the service is initiated.
20 Enterprise and Enbridge intend to honor the discounted rates that they previously offered
21 in a recent open season to shippers that signed-up for long term volume commitments on
22 a similar Cushing to Houston pipeline project, but those discounted rates will likely not
23 take effect until2013. Enterprise and Enbridge also anticipate that there will be an C,<
-4- 20111202-5190 FERC PDF (Unofficial) 12/2/2011 4:46:13 PM
1 additional open season to determine if there is sufficient shipper interest to further expand
2 the Reversed Seaway Pipeline. Depending upon the amount of shipper interest, it is
3 anticipated that the Reversed Seaway Pipeline may be further expanded in order to permit
4 approximately 500,000 barrels per day of capacity in addition to the currently-planned
5 approximately 375,000 barrels per day of capacity. Any such additional expansion would
6 likely go into service in the first half of 2014.
7
8 Q. Have you reviewed the competitive and other constraints in the markets at issue, as
9 identified by Dr. Schink in his testimony (included in Statement I) and the other
10 statements that accompany this Application?
11 A. Yes, I have. The competitive factors that Dr. Schink identifies are consistent with my
12 understanding of these markets, based on my experience with Seaway and my knowledge ( ( 13 of the crude oil industry.
14
15 Q. Why are Enterprise and Enbridge requesting authority to charge market-based rates on
16 the Reversed Seaway Pipeline?
17 A. Enterprise and Enbridge seek market-based rates in order to have greater flexibility in
18 setting rates for the applicable origin and destination markets than would otherwise be
19 available under the Commission's indexing and cost-of-service ratemaking regulations.
20 Market-based rates would provide the ability to adjust the rates for the Reversed Seaway
21 Pipeline in response to market demand and competition. This flexibility in rate setting is
22 especially important for the Reversed Seaway Pipeline, since it is a new entrant to the
(-··> ', ___(
- 5- 20111202-5190 FERC PDF (Unofficial) 12/2/2011 4:46:13 PM
(--- 1 market that must compete with the numerous existing and potential alternatives for ., 2 exporting crude oil from Cushing and delivering crude oil to the Gulf Coast.
3
4 Q. Are Enterprise and Enbridge effectively seeking deregulation in the markets affected by
5 this Application?
6 A. No, they are simply requesting that in the applicable origin and destination markets, the
7 current indexing and cost-of service constraints be removed and the competitive forces of
8 the market place be allowed to operate in their place. Should this Application be granted,
9 the Reversed Seaway Pipeline will file tariffs with the Commission, and its rates and
10 services will continue to be subject to all of the non-discrimination requirements of the
11 Interstate Commerce Act that would apply if the Application had never been filed.
( -·- 12
...... _ -~ 13 Q. Does this conclude your prepared direct testimony?
14 A. Yes.
- 6- UNITED STATES OF·AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION
Enterprise Products Partners L.P. ) Docket No. OR12-" ___ and Enbridge Inc. )
vERifiCATION OF MARK A· HURLEX
I, Mark A. Hurley, am the witness whose Prepared Direct Testimony is submitted herewith. If asked the questions that appear in the text of this Prepared Direct Testimony, I would give the answers that are also set forth therein, and I adopt this Prepared Direct Testimony as my sworn testimony in this proceeding.
Pursuant to 28 U.S.C. § 1746, I declare under penalty of perjury that the foregoing is true ( and correct.
Executed this l st day of December, 2011. 20111202-5190 FERC PDF (Unofficial) 12/2/2011 4:46:13 PM Document Content(s)
Cover Letter.PDF ...... 1-2
( -~ :-idge MBR Application. PDF ...... 3-20 '"· Statement A. PDF ...... 21-62
Statement B.PDF ...... 63-68
Statement C. PDF ...... 69-7 6
Statement D. PDF ...... 77-120
Statement E.PDF ...... 121-147
Statement F. PDF ...... 148-160
Statement G. PDF ...... ~ ...... 161-236
Statement H. PDF ...... 237-245
Statement I.PDF ...... 246-320 ((
APPENDIX 1 TO SEMI/SEPP 1.11 ( ( r~ (I /~! f Appendix (~;/SEPP 1.11 ';
1 2009 OCT NOV DEC 2 Total volume of refined products Shipped 56,178 78,240 66,428 3 4 5 2010 JANUARY FEBRUARY MARCH APRIL MAY JUNE JULY AUG SEPT OCT NOV DEC 6 Total volume of refined products Shipped 51,072 51,074 45,962 24,039 47,259 30,449 54,767 63,176 36,049 44,613 49,545 55,419 7 8 9 2011 JANUARY FEBRUARY MARCH APRIL MAY JUNE JULY AUG SEPT OCT NOV DEC 10 Total volume of refined products Shipped 50,272 45,320 35,966 24,164 31,460 39,461 58,879 62,140 61,362 52,288 52,761 49,864 11 12 13 2012 JANUARY FEBRUARY MARCH APRIL MAY JUNE JULY AUG SEPT OCT 14 Total volume of refined products Shipped 54,717 69,489 41,755 33,154 43,344 29,880 44,497 54,651 50,715 44,034
Page 1 of 1 APPENDIX 1 TO SEMI/SEPP 1.17 ( \_ Appendix 1 to SEMI/SEPP 1.17
Cumulative Effect of Increase in the Fixed Toll Component
Indicative Firm Service Fixed Toll Component
After 20 Years2 After 20 Years2 20 Yr Term Fixed Increasing by 2.5% Increasing by 3% Location Crude Toll ComJ1onent Each Year Each Year ED-KAM Light 2.84 4.65 5.13 ED-SUMAS Light 3.80 6.23 6.86 ED-BBY Light 3.99 6.54 7.21 ED-WEST Light 4.48 7.34 8.09 ED-WEST Heavy 4.48 7.34 8.09
Note: The tariffs listed in footnote 130 of the evidence under the column labeled "Trans Mountain Expansion 20yr $/bbl" are the Total of the Fixed and Variable Indicative Firm Service Toll Components. APPENDIX 2 TO SEMJJSEPP 1.27 ( ( Appendix A Page 18 of28 . J.{eyisf!4 onNovember 24, 2012. With Committed Enbridge With Uncommitted En bridge i Southern lights Tariff Rates : Southern lights Tariff Rates Returned Rail : Pipeline ; . Rail Pipeline Move Product ,Cars Cost 1 Cost Diff i Cost Cost Rail Dollar Per Barrel Dollar Per Barrel Mfus ·Edmonton to Vancouver Crude .. Empty $5.6i $4.91-$0.7 $5.6: .. $4:91 J0.7 779! ·Crude Condensate $1.4i $4.9i $3.5' -$6.9! $4.9! $11.8( 779' F~~~~~+y to.y¥~~u+~;.. ·. B~n.;Empty S6.o $9.~Cs3:7L . $6.(} . $9.8::; .$3;1f ····.11,0066i~l . .. <··~· ,, , . .. · Biturrexi:· Condensat~: $1.1 ; .·.· $9:8" $8.71 -$7.2' ·. $9.81 $17.01 . ' .. \11 .Ed!lXl~ton to USGC (St Jrures) Crude Empty $13.41 $9.0: -$4.4l $13.4! $9.0! -$4..4! 2,6701 Crude $8.5i $9.0: $0.5' $0.2: $9.01 $8.8i 2,670i Biturreiri Empty• Sk35.·:. s1s.1. sr6j $13.5 i $15.1. ·. SL6{ 2,96jj .· Biililren . Condell$atec .$7.2'( $15,1 ss.of -sir: . s1s.c $1${3( 2,9()~ Bitumen Empty $6.6! $7.0! $0.4: Fort McMurrayto} Ed~itilir1toP6rtlarld;.ME(vill. Crude~ Empt}( · ' $12.&: $9:3 -$3.51 $12:& > $9;3 -$3.5{ ·2,446'1 Mo#aiJ ..\! '.. •· · • . Cfude;: ; Ci:mdens~te,>. ..•. S8.i . $9.3\I $1.~ c$0,2' $9,j':.' $9,6~ .. 2,446J .Fort McMurray to Portland, ME Bitumen Empty $-1?-:7( $15.3! $2.6: $12.T $15.3! $2.6' 2,738i ·(via Montreal) Bitumen .Condensate $7.9! $15.3: $7.4; -$0.4· $15.3c $15.7: 2,738' D. Conclusions for Rail Movements of Western Canada Crude Oil 25. Based on the analysis I presented above, I conclude that, in Western Canada, rail has become an increasingly cost-effective transporter for crude oil. My evaluation of rail as a cost-effective competitor to pipelines exiting Western Canada relies on a detailed analysis of estimates of the relative costs of using rail versus pipeline for specific movements from Western Canada for blended bitumen and undiluted bitumen. My analysis considers unique economic advantages of rail movements that can deliver condensate back to Western Canada (instead of returning empty cars). In addition, I consider the economic benefits of shipping undiluted bitumen by rail cars which avoids the cost to pipelines of delivering and mixing condensate with bitumen and enables additional volumes of bitumen to be shipped. My analysis demonstrates that while rail is somewhat more expensive for undiluted bitumen deliveries originating in Western Canada, rail is generally less expensive for bitumen deliveries, and the railroads' ability to backhaul condensate to the origin market provides significant additional economic benefits. 26. I also conclude that the CN and CP railroads, which are the two rail carriers with major presences in Western Canada, should be included as competitors to pipelines in the APPENDIX 1 TO SEMI/ SEPP 1.30 REVISED JANUARY 10, 2013 Appendix 1 to SEMI/SEPP 1.30 Current, Expected, and Potential Competitors in the Western Canada Crude Oil Origin Market Revised January 10,2013 I. 2011- Early 2013 Current Competitors A. Crude Oil Pipelines 1. Kinder Morgan a. Trans Mountain 2. Enbridge Mainline 3. Express/Platte 4. Inter Pipeline Bow River 5. Plains Rangeland 6. TransCanada a. Keystone B. Refineries 1. Consumers' Cooperative 2. Husky Oil Operations 3. Imperial Oil 4. Moose Jaw Asphalt 5. Shell Canada 6. Suncor Energy C. Rail 1. Canadian Pacific to Vancouver II. Additional Competitors in 2015 A. Crude Oil Pipelines 1. TransCanada a. Keystone XL Ill. Additional Competitors in 2017 A. Crude Oil Pipelines 1. Kinder Morgan a. Trans Mountain Expansion B. Potential Rail Entry 1. Canadian National 2. Canadian Pacific IV. Additional Competitors in 2018 A. Crude Oil Pipelines 1. Enbridge Only One of the Two a. Northern Gateway (With Capacity of 525 MBD) Pipelines is Assumed to 2. TransCanada be Built in 2018 a. Hypothetical East Coast Pipeline (With Capacity of 525 MBD) t Appendix 1 to SEMIISEPP 1.30 Western Canada Crude Oil Origin Market Unadjusted Capacity Shares Revised January 10,2013 Trans Mountain En bridge TransCanada Unadjusted Unadjusted Unadjusted Date/ Market Events Ca~aci!Y Share Ca~acit~ Share Ca~acit~ Share 2011-Early 2013 6.9% 57.7% 13.6% (Current Situation) Future: Potential Rail Entry Does Not Occur a. 2015 5.8% 48.4% 27.5% (Keystone XL Completed) 2a b. 2017 15.5% 43.4% 24.7% (Trans Mountain Expansion Completed) 2b c. 2018 14.2% 48.2% 22.6% (Northern Gateway Completed) 2c Future: Potential Rail Entry Occurs a. 2017 14.7% 41.4% 23.5% (Trans Mountain Expansion Completed) 3a b. 2018 13.5% 46.0% 21.6% 3b (Northern Gateway Completed) Appendix 1 to SEMI/SEPP 1.30 Market Shares for the Western Canada Crude Oil Origin Market 2011-2012 Current Situation Revised January 10, 2013 Facility Company Share of Capacities Capacities Market {MBD} {MBD} {%2 col. 1 Col.2 Col. 3 Crude Oil Pipelines Kinder Morgan 300.0 300.0 6.9 Trans Mountain 300.0 Enbridge 2,499.7 2,499.7 57.7 Mainline 2,499.7 Express/Platte 245.0 245.0 5.7 Inter Pipeline Bow River 30.0 30.0 0.7 Plains Rangeland 85.0 85.0 2.0 TransCanada 590.0 590.0 13.6 Keystone 590.0 Subtotal Crude Oil Pipelines 3,749.7 3,749.7 86.5 Refineries Consumers' Cooperative 100.0 100.0 2.3 Husky Oil Operations 25.0 25.0 0.6 Imperial Oil 189.0 189.0 4.4 Moose Jaw Asphalt 14.0 14.0 0.3 Shell Canada 100.0 100.0 2.3 Suncor Energy 147.0 147.0 3.4 Subtotal Refineries 575.0 575.0 13.3 Existing Rail Canadian Pacific 11.0 11.0 0.3 Subtotal Existing Hail 11.0 11.0 0.3 Total 4,335.7 4,335.7 100.0 Appendix 1 to SEMI/SEPP 1.30 Market Shares for the Western Canada Crude Oil Origin Market 2015: Keystone XL Completed Revised January 10, 2013 Facility Company Share of Capacities Capacities Market (MBD) (MBD) (%) col. 1 Col. 2 Col. 3 Crude Oil Pipelines Kinder Morgan 300.0 300.0 5.8 Trans Mountain 300.0 En bridge 2,499.7 2,499.7 48.4 Mainline 2,499.7 Express/Platte 245.0 245.0 4.7 Inter Pipeline Bow River 30.0 30.0 0.6 Plains Rangeland 85.0 85.0 1.6 TransCanada 1,420.0 1,420.0 27.5 Keystone 590.0 Keystone XL 830.0 Subtotal Crude Oil Pipelines 4,579.7 4,579.7 88.7 Refineries Consumers' Cooperative 100.0 100.0 1.9 Husky Oil Operations 25.0 25.0 0.5 Imperial Oil 189.0 189.0 3.7 Moose Jaw Asphalt 14.0 14.0 0.3 Shell Canada 100.0 100.0 1.9 Suncor Energy 147.0 147.0 2.8 Subtotal Refineries 575.0 575.0 11.1 Existing Rail Canadian Pacific 11.0 11.0 0.2 Subtotal Existing Rail 11.0 11.0 0.2 Total 5,165.7 5,165.7 100.0 Appendix 1 to SEMI/SEPP 1.30 Market Shares for the Western Canada Crude Oil Origin Market 2017: Trans Mountain Expansions and Keystone XL Completed Excluding Potential Rail Entry Revised January 10,2013 Facility Company Share of Capacities Capacities Market (MBD) (MBD) (%) col. 1 Col. 2 Col. 3 Crude Oil Pipelines Kinder Morgan 890.0 890.0 15.5 Trans Mountain 300.0 Trans Mountain Expansion 590.0 Enbridge 2,499.7 2,499.7 43.4 Mainline 2,499.7 Express/Platte 245.0 245.0 4.3 Inter Pipeline Bow River 30.0 30.0 0.5 Plains Rangeland 85.0 85.0 1.5 TransCanada 1,420.0 1,420.0 24.7 Keystone 590.0 Keystone XL 830.0 Subtotal Crude Oil Pipelines 5,169.7 5,169.7 89.8 Refineries Consumers' Cooperative 100.0 100.0 1.7 Husky Oil Operations 25.0 25.0 0.4 Imperial Oil 189.0 189.0 3.3 Moose Jaw Asphalt 14.0 14.0 0.2 Shell Canada 100.0 100.0 1.7 Suncor Energy 147.0 147.0 2.6 Subtotal Refineries 575.0 575.0 10.0 Existing Rail Canadian Pacific 11.0 11.0 0.2 Subtotal Existing Rail 11.0 11.0 0.2 Total 5,755.7 5,755.7 100.0 Appendix 1 to SEMI/SEPP 1.30 Market Shares for the Western Canada Crude Oil Origin Market 2018: Trans Mountain Expansion, Keystone XL, and Northern Gateway Completed Excluding Potential Rail Entry Revised January 10, 2013 Facility Company Share of Capacities Capacities Market {MBD} {MBD} {%} col. 1 Col.2 Col. 3 Crude Oil Pipelines Kinder Morgan 890.0 890.0 14.2 Trans Mountain 300.0 Trans Mountain Expansion 590.0 En bridge 3,024.7 3,024.7 48.2 Mainline 2,499.7 Northern Gateway 525.0 Express/Platte 245.0 245.0 3.9 Inter Pipeline Bow River 30.0 30.0 0.5 Plains Rangeland 85.0 85.0 1.4 TransCanada 1,420.0 1,420.0 22.6 Keystone 590.0 Keystone XL 830.0 Subtotal Crude Oil Pipelines 5,694.7 5,694.7 90.7 Refineries Consumers' Cooperative 100.0 100.0 1.6 Husky Oil Operations 25.0 25.0 0.4 Imperial Oil 189.0 189.0 3.0 Moose Jaw Asphalt 14.0 14.0 0.2 Shell Canada 100.0 100.0 1.6 Suncor Energy 147.0 147.0 2.3 Subtotal Refineries 575.0 575.0 9.2 Existing Rail Canadian Pacific 11.0 11.0 0.2 Subtotal Existing Rail 11.0 11.0 0.2 Total 6,280.7 6,280.7 100.0 Appendix 1 to SEMI/SEPP 1.30 Western Canada Crude Oil Origin Market Adjusted Capacity HHis Revised January 10, 2013 Adjusted Date/ Market Events Capacity HHI I. 2011-Early 2013 2,062 (Current Situation) II. Future: Potential Rail Entry Does Not Occur a. 2015 2,466 (Keystone XL Completed) b. 2017 2,148 (Trans Mountain Expansion Completed) c. 2018 2,189 (Northern Gateway Completed) Ill. Future: Potential Rail Entry Occurs a. 2017 1,812 (Keystone XL and Trans Mountain Expansion Completed) b. 2018 1,854 (Northern Gateway Completed) Appendix 1 to SEMI/SEPP 1.30 Adjusted Capacity Based HHI for the Western Canada Crude Oil Origin Market 2011-Early 2013: Current Situation Revised January 10, 2013 Facility Company Adjusted Adjusted Capacities Capacities Capacities Capacity Share HHI (MBD) (MBD) (MBD) (%) Contributi• Col. 1 Col. 2 Col. 3 Col. 4 Col. 5 Crude Oil Pipelines Kinder Morgan 300.0 300.0 300.0 10.3 106 Trans Mountain 300.0 En bridge 2,499.7 2,499.7 1,082.3 37.1 1,375 Mainline 2,499.7 Express/Platte 245.0 245.0 245.0 8.4 70 Inter Pipeline Bow River 30.0 30.0 30.0 1.0 1 Plains Rangeland 85.0 85.0 85.0 2.9 8 TransCanada 590.0 590.0 590.0 20.2 409 Keystone 590.0 Subtotal Crude Oil Pipelines 3,749.7 3,749.7 2,332.3 79.9 Refineries Consumers' Cooperative 100.0 100.0 100.0 3.4 12 Husky Oil Operations 25.0 25.0 25.0 0.9 1 Imperial Oil 189.0 189.0 189.0 6.5 42 Moose Jaw Asphalt 14.0 14.0 14.0 0.5 0 Shell Canada 100.0 100.0 100.0 3.4 12 Suncor Energy 147.0 147.0 147.0 5.0 25 Subtotal Refineries 575.0 575.0 575.0 19.7 Existing Rail Canadian Pacific 11.0 11.0 11.0 0.4 0 Subtotal Existing Rail 11.0 11.0 11.0 0.4 Total 4,335.7 4,335.7 2,918.2 100.0 Capacity 2,918.2 2,062 2011 Western Canada Crude Oil Supply (MBD) Based HHI Appendix 1 to SEMI/SEPP 1.30 Adjusted Capacity Based HHI for the Western Canada Crude Oil Origin Market 2015: Keystone XL Completed Revised January 10, 2013 Facility Company Adjusted Adjusted Capacities Capacities Capacities Capacity Share HHI (MBD) (MBD) (MBD) (%) Contributi' Col. 1 Col. 2 Col. 3 Col. 4 Col. 5 Crude Oil Pipelines Kinder Morgan 300.0 300.0 300.0 7.7 59 Trans Mountain 300.0 En bridge 2,499.7 2,499.7 1,321.8 34.0 1,155 Mainline 2,499.7 Express/Platte 245.0 245.0 245.0 6.3 40 Inter Pipeline Bow River 30.0 30.0 30.0 0.8 1 Plains Rangeland 85.0 85.0 85.0 2.2 5 TransCanada 1,420.0 1,420.0 1,321.8 34.0 1,155 Keystone 590.0 Keystone XL 830.0 Subtotal Crude Oil Pipelines 4,579.7 4,579.7 3,303.5 84.9 Refineries Consumers' Cooperative 100.0 100.0 100.0 2.6 7 Husky Oil Operations 25.0 25.0 25.0 0.6 0 Imperial Oil 189.0 189.0 189.0 4.9 24 Moose Jaw Asphalt 14.0 14.0 14.0 0.4 0 Shell Canada 100.0 100.0 100.0 2.6 7 Suncor Energy 147.0 147.0 147.0 3.8 14 Subtotal Refineries 575.0 575.0 575.0 14.8 Existing Rail Canadian Pacific 11.0 11.0 11.0 0.3 0 Subtotal Existing Rail 11.0 11.0 11.0 0.3 Total 5,165.7 5,165.7 3,889.5 100.0 Capacity 2015 Western Canada Crude Oil Supply (MBD) 3,889.5 2,466 Based HHI Appendix 1 to SEMI/SEPP 1.30 Adjusted Capacity Based HHI for the Western Canada Crude Oil Origin Market 2017: Trans Mountain Expansion Completed; Excluding Potential Rail Entry Revised January 10, 2013 Facility Company Adjusted Adjusted Capacities Capacities Capacities Capacity Share HHI {MBDl {MBDl (MBD) (%) Contributi• Col. 1 Col.2 Col. 3 Col.4 Col. 5 Crude Oil Pipelines Kinder Morgan 890.0 890.0 890.0 20.7 429 Trans Mountain 300.0 Trans Mountain Expansion 590.0 En bridge 2,499.7 2,499.7 1,229.3 28.6 819 Mainline 2,499.7 Express/Platte 245.0 245.0 245.0 5.7 33 Inter Pipeline Bow River 30.0 30.0 30.0 0.7 0 Plains Rangeland 85.0 85.0 85.0 2.0 4 TransCanada 1,420.0 1,420.0 1,229.3 28.6 819 Keystone 590.0 Keystone XL 830.0 Subtotal Crude Oil Pipelines 5,169.7 5,169.7 3,708.7 86.4 Refineries Consumers' Cooperative 100.0 100.0 100.0 2.3 5 Husky Oil Operations 25.0 25.0 25.0 0.6 0 Imperial Oil 189.0 189.0 189.0 4.4 19 Moose Jaw Asphalt 14.0 14.0 14.0 0.3 0 Shell Canada 100.0 100.0 100.0 2.3 5 Suncor Energy 147.0 147.0 147.0 3.4 12 Subtotal Refineries 575.0 575.0 575.0 13.4 Existing Rail Canadian Pacific 11.0 11.0 11.0 0.3 0 Subtotal Existing Rail 11.0 11.0 11.0 0.3 Total 5,755.7 5,755.7 4,294.7 100.0 Capacity- 4,294.7 2,148 2017 Western Canada Crude Oil Supply (MBD) Based HHI Appendix 1 to SEMI/SEPP 1.30 Adjusted Capacity Based HHI for the Western Canada Crude Oil Origin Market 2018: Northern Gateway Completed; Excluding Potential Rail Entry Revised January 10, 2013 Facility Company Adjusted Adjusted Capacities Capacities Capacities Capacity Share HHI {MBD} {MBD} {MBD} {%} Contributi• Col.1 Col.2 Col. 3 Col.4 Col. 5 Crude Oil Pipelines Kinder Morgan 890.0 890.0 890.0 20.1 405 Trans Mountain 300.0 Trans Mountain Expansion 590.0 En bridge 3,024.7 3,024.7 1,292.2 29.2 855 Mainline 2,499.7 Northern Gateway 525.0 Express/Platte 245.0 245.0 245.0 5.5 31 Inter Pipeline Bow River 30.0 30.0 30.0 0.7 0 Plains Rangeland 85.0 85.0 85.0 1.9 4 TransCanada 1,420.0 1,420.0 1,292.2 29.2 855 Keystone 590.0 Keystone XL 830.0 Subtotal Crude Oil Pipelines 5,694.7 5,694.7 3,834.3 86.7 Refineries Consumers' Cooperative 100.0 100.0 100.0 2.3 5 Husky Oil Operations 25.0 25.0 25.0 0.6 0 Imperial Oil 189.0 189.0 189.0 4.3 18 Moose Jaw Asphalt 14.0 14.0 14.0 0.3 0 Shell Canada 100.0 100.0 100.0 2.3 5 Suncor Energy 147.0 147.0 147.0 3.3 11 Subtotal Refineries 575.0 575.0 575.0 13.0 Existing Rail Canadian Pacific 11.0 11.0 11.0 0.2 0 Subtotal Existing Rail 11.0 11.0 11.0 0.2 Total 6,280.7 6,280.7 4,420.3 100.0 Capacity- 2,189 2018 Western Canada Crude Oil Supply (MBD) 4,420.3 Based HHI Appendix 1 to SEMI/SEPP 1.30 Adjusted Capacity Based HHI for the Western Canada Crude Oil Origin Market 2018: Hypothetical 525 MBD TransCanada East Coast Pipeline Completed; Excluding Potential Rail Entry Revised January 10, 2013 Facility Company Adjusted Adjusted Capacities Capacities Capacities Capacity Share HHI (MBD} (MBD} (MBD} (%} Contributi• Col. 1 Col.2 Col. 3 Col.4 Col. 5 Crude Oil Pipelines Kinder Morgan 890.0 890.0 890.0 20.1 405 Trans Mountain 300.0 Trans Mountain Expansion 590.0 En bridge 2,499.7 2,499.7 1,292.2 29.2 855 Mainline 2,499.7 Express/Platte 245.0 245.0 245.0 5.5 31 Inter Pipeline Bow River 30.0 30.0 30.0 0.7 0 Plains Rangeland 85.0 85.0 85.0 1.9 4 TransCanada 1,945.0 1,945.0 1,292.2 29.2 855 Keystone 590.0 Keystone XL 830.0 Hypothetical East Coast Pipeline (525 MBD) 525.0 Subtotal Crude Oil Pipelines 5,694.7 5,694.7 3,834.3 86.7 Refineries Consumers' Cooperative 100.0 100.0 100.0 2.3 5 Husky Oil Operations 25.0 25.0 25.0 0.6 0 Imperial Oil 189.0 189.0 189.0 4.3 18 Moose Jaw Asphalt 14.0 14.0 14.0 0.3 0 Shell Canada 100.0 100.0 100.0 2.3 5 Suncor Energy 147.0 147.0 147.0 3.3 11 Subtotal Refineries 575.0 575.0 575.0 13.0 Existing Rail Canadian Pacific 11.0 11.0 11.0 0.2 0 Subtotal Existing Rail 11.0 11.0 11.0 0.2 Total 6,280.7 6,280.7 4,420.3 100.0 Capacity- 2018 Western Canada Crude Oil Supply (MBD) 4,420.3 2,189 Based HHI Appendix 1 to SEMI/SEPP 1.30 Adjusted Capacity Based HHI for the Western Canada Crude Oil Origin Market 2017: Trans Mountain Expansion Completed; Including Potential Rail Revised January 10, 2013 Facility Company Adjusted Adjusted Capacities Capacities Capacities Capacity Share HHI (MBD} {MBD} {MBD} {%} Contributi• Col.1 Col. 2 Col. 3 Col.4 Col. 5 Crude Oil Pipelines Kinder Morgan 890.0 890.0 890.0 20.7 429 Trans Mountain 300.0 Trans Mountain Expansion 590.0 En bridge 2,499.7 2,499.7 1,084.8 25.3 638 Mainline 2,499.7 Express/Platte 245.0 245.0 245.0 5.7 33 Inter Pipeline Bow River 30.0 30.0 30.0 0.7 0 Plains Rangeland 85.0 85.0 85.0 2.0 4 TransCanada 1,420.0 1,420.0 1,084.8 25.3 638 Keystone 590.0 Keystone XL 830.0 Subtotal Crude Oil Pipelines 5,169.7 5,169.7 3,419.7 79.6 Refineries Consumers' Cooperative 100.0 100.0 100.0 2.3 5 Husky Oil Operations 25.0 25.0 25.0 0.6 0 Imperial Oil 189.0 189.0 189.0 4.4 19 Moose Jaw Asphalt 14.0 14.0 14.0 0.3 0 Shell Canada 100.0 100.0 100.0 2.3 5 Suncor Energy 147.0 147.0 147.0 3.4 12 Subtotal Refineries 575.0 575.0 575.0 13.4 Potential Rail Entry Canadian National 200.0 200.0 200.0 4.7 22 Canadian Pacific 100.0 100.0 100.0 2.3 5 Subtotal Potential Rail Entry 300.0 300.0 300.0 7.0 Total 6,044.7 6,044.7 4,294.7 100.0 Capacity- 4,294.7 1,812 2017 Western Canada Crude Oil Supply (MBD) Based HHI Appendix 1 to SEMI/SEPP 1.30 Adjusted Capacity Based HHI for the Western Canada Crude Oil Origin Market 2018: Northern Gateway Completed; Including Potential Rail Revised January 10, 2013 Facility Company Adjusted Adjusted Capacities Capacities Capacities Capacity Share HHI {MBD~ {MBD~ {MBD~ {%~ Contributi' Col. 1 Col.2 Col. 3 Col. 4 Col. 5 Crude Oil Pipelines Kinder Morgan 890.0 890.0 890.0 20.1 405 Trans Mountain 300.0 Trans Mountain Expansion 590.0 Enbridge 3,024.7 3,024.7 1,147.7 26.0 674 Mainline 2,499.7 Northern Gateway 525.0 Express/Platte 245.0 245.0 245.0 5.5 31 Inter Pipeline Bow River 30.0 30.0 30.0 0.7 0 Plains Rangeland 85.0 85.0 85.0 1.9 4 TransCanada 1,420.0 1,420.0 1,147.7 26.0 674 Keystone 590.0 Keystone XL 830.0 Subtotal Crude Oil Pipelines 5,694.7 5,694.7 3,545.3 80.2 Refineries Consumers' Cooperative 100.0 100.0 100.0 2.3 5 Husky Oil Operations 25.0 25.0 25.0 0.6 0 Imperial Oil 189.0 189.0 189.0 4.3 18 Moose Jaw Asphalt 14.0 14.0 14.0 0.3 0 Shell Canada 100.0 100.0 100.0 2.3 5 Suncor Energy 147.0 147.0 147.0 3.3 11 Subtotal Refineries 575.0 575.0 575.0 13.0 Potential Rail Entry Canadian National 200.0 200.0 200.0 4.5 20 Canadian Pacific 100.0 100.0 100.0 2.3 5 Subtotal Potential Rail Entry 300.0 300.0 300.0 6.8 Total 6,569.7 6,569.7 4,420.3 100.0 Capacity- 4,420.3 1,854 2018 Western Canada Crude Oil Supply (MBD) Based HHI Appendix 1 to SEMI/SEPP 1.30 Adjusted Capacity Based HHI for the Western Canada Crude Oil Origin Market 2018: Hypothetical 525 MBD TransCanada East Coast Pipeline Completed; Including Potential Rail Revised January 10, 2013 Facility Company Adjusted Adjusted Capacities Capacities Capacities Capacity Share HHI (MBD) (MBD) (MBD) (%) Contributi' Col.1 Col. 2 Col. 3 Col.4 Col. 5 Crude Oil Pipelines Kinder Morgan 890.0 890.0 890.0 20.1 405 Trans Mountain 300.0 Trans Mountain Expansion 590.0 Enbridge 2,499.7 2,499.7 1,147.7 26.0 674 Mainline 2,499.7 Express/Platte 245.0 245.0 245.0 5.5 31 Inter Pipeline Bow River 30.0 30.0 30.0 0.7 0 Plains Rangeland 85.0 85.0 85.0 1.9 4 TransCanada 1,945.0 1,945.0 1,147.7 26.0 674 Keystone 590.0 Keystone XL 830.0 Hypothetical East Coast Pipeline (525 MBD) 525.0 Subtotal Crude Oil Pipelines 5,694.7 5,694.7 3,545.3 80.2 Refineries Consumers' Cooperative 100.0 100.0 100.0 2.3 5 Husky Oil Operations 25.0 25.0 25.0 0.6 0 Imperial Oil 189.0 189.0 189.0 4.3 18 Moose Jaw Asphalt 14.0 14.0 14.0 0.3 0 Shell Canada 100.0 100.0 100.0 2.3 5 Suncor Energy 147.0 147.0 147.0 3.3 11 Subtotal Refineries 575.0 575.0 575.0 13.0 Potential Rail Entry Canadian National 200.0 200.0 200.0 4.5 20 Canadian Pacific 100.0 100.0 100.0 2.3 5 Subtotal Potential Rail Entry 300.0 300.0 300.0 6.8 Total 6,569.7 6,569.7 4,420.3 100.0 Capacity- 4,420.3 1,854 2018 Western Canada Crude Oil Supply (MBD) Based HHI Appendix 1 to SEMI/SEPP 1.30 Forecast Western Canada Crude Oil Supply Western Canada Crude Oil Supply (MBD) 2011 Current 2,918.2 2015 Keystone XL Completed 3,889.5 2017 Trans Mountain Expansion Completed 4,294.7 2018 Enbridge Northern Gateway Completed 4,420.3 Appendix 1 to SEMI/SEPP 1.30 Current, Expected, and Potential Competitors in the Combined Vancouver Area and Puget Sound Crude Oil Destination Market Revised January 10, 2013 I. 2011-Early 2013 Current Competitors A. Crude Oil Pipelines 1. Kinder Morgan a. Trans Mountain B. Rail from Western Canada 1. Canadian Pacific C. Overseas Competitors 1. Four Overseas Competitors D. Waterborne Deliveries to Puqet Sound Area II. Additional Competitors in 2017 A. Crude Oil Pipelines 1. Kinder Morgan a. Trans Mountain Expansion B. Overseas Competitors 1. Six Additional Overseas Competitors C. Potential Waterborne 1. Waterborne Deliveries to the Vancouver Area D. Potential Rail Entrv in the Vancouver Area 1. Canadian National 2. Canadian Pacific Appendix 1 to SEMI/SEPP 1.30 Combined Vancouver Area and Puget Sound Crude Oil Destination Market Unadjusted Capacity Shares Revised January 10, 2013 Trans Mountain Waterborne Unadjusted Unadjusted Date/ Market Events Ca~acity Share Ca~acity Share I. 2011 32.9% 44.0% (Current Situation Including Existing Rail and Truck and Overseas Competitors) II. Future: Potential Rail and Waterborne Entry Does Not Occur a. 2017 49.4% 22.3% (Trans Mountain Expansion Completed) Ill. Future: Potential Rail and Waterborne Entry Occurs a. 2017 47.6% 22.5% (Trans Mountain Expansion Completed) Appednix 1 to SEMI/SEPP 1.30 Market Shares for the Vancouver Area and Puget Sound Crude Oil Destination Market 2011-2012 Situation; Existing Rail and Truck Revised January 10, 2013 Facility Company Share of Capacities Capacities Market (M8D} (M8D} (%} Col.1 Col. 2 Col. 3 Crude Oil Pipelines Kinder Morgan 300.0 300.0 32.9 Trans Mountain 300.0 Subtotal Crude Oil Pipelines 300.0 300.0 32.9 Existing Rail and Truck Canadian Pacific 11.0 11.0 1.2 Subtotal Existing Rail and Truck 11.0 11.0 1.2 Overseas Competitors Competitor 1 50.0 50.0 5.5 Competitor 2 50.0 50.0 5.5 Competitor 3 50.0 50.0 5.5 Competitor 4 50.0 50.0 5.5 Subtotal Overseas Competitors 200.0 200.0 21.9 Waterborne 401.1 401.1 44.0 Total 912.1 912.1 100.0 Market Shares for the Vancouver Area and Puget Sound Crude Oil Destination Market 2017: Trans Mountain Expansion Excluding Future Rail Revised January 10, 2013 Facility Company Share of Capacities Capacities Market ~8~ ~8~ ~} Col. 1 Col. 2 Col. 3 Crude Oil Pipelines Kinder Morgan 890.0 890.0 49.4 Trans Mountain 300.0 Trans Mountain Expansion 590.0 Subtotal Crude Oil Pipelines 890.0 890.0 49.4 Existing Rail and Truck Canadian Pacific 11.0 11.0 0.6 Subtotal Existing Rail and Truck 11.0 11.0 0.6 Overseas Competitors Competitor 1 50.0 50.0 2.8 Competitor 2 50.0 50.0 2.8 Competitor 3 50.0 50.0 2.8 Competitor 4 50.0 50.0 2.8 Competitor 5 50.0 50.0 2.8 Competitor 6 50.0 50.0 2.8 Competitor 7 50.0 50.0 2.8 Competitor 8 50.0 50.0 2.8 Competitor 9 50.0 50.0 2.8 Appednix 1 to SEMI/SEPP 1.30 Competitor 10 50.0 50.0 2.8 Subtotal Overseas Competitors 500.0 500.0 27.7 Waterborne 401.1 401.1 22.3 Total 1,802.1 1,802.1 100.0 Appednix 1 to SEMI/SEPP 1.30 Market Shares for the Vancouver Area and Puget Sound Crude Oil Destination Market 2017: Trans Mountain Expansion; Including New Waterborne Deliveries Revised January 10, 2013 Facility Company Share of Capacities Capacities Market (MBD) (MBD) (%) Col. 1 Col. 2 Col. 3 Crude Oil Pipelines Kinder Morgan 890.0 890.0 47.6 Trans Mountain 300.0 Trans Mountain Expansion 590.0 Subtotal Crude Oil Pipelines 890.0 890.0 47.6 Potential Rail Entry Canadian National 30.0 30.0 1.6 Canadian Pacific 30.0 30.0 1.6 Subtotal Potential Rail Entry 60.0 60.0 3.2 Overseas Competitors Competitor 1 50.0 50.0 2.7 Competitor 2 50.0 50.0 2.7 Competitor 3 50.0 50.0 2.7 Competitor 4 50.0 50.0 2.7 Competitor 5 50.0 50.0 2.7 Competitor 6 50.0 50.0 2.7 Competitor 7 50.0 50.0 2.7 Competitor 8 50.0 50.0 2.7 Competitor 9 50.0 50.0 2.7 Competitor 10 50.0 50.0 2.7 Subtotal Overseas Competitors 500.0 500.0 26.7 Waterborne Existing Waterborne 401.1 401.1 21.4 New Inbound Waterborne 20.0 20.0 1.1 Subtotal Waterborne 421.1 421.1 22.5 Total 1,871.1 1,871.1 100.0 Appendix 1 to SEMI/SEPP 1.30 Combined Vancouver Area and Puget Sound Crude Oil Destination Market Adjusted Capacity HHis Revised January 10, 2013 Adjusted Date/ Market Events Capacity HHI I. 2011 338 (Current Situation Including Existing Rail and Truck and Overseas Competitors) II. Future: Potential Rail and Waterborne Entry Does Not Occur a. 2017 950 (Trans Mountain Expansion Completed) Ill. Future: Potential Rail and Waterborne Entry Occurs a. 2017 684 (Trans Mountain Expansion Completed) Appendix to SEMI/SEPP 1.30 Adjusted Capacity Based HHI for the Vancouver Area and Puget Sound Crude Oil Destination Market 2011-Early 2013 Current Situation: Existing Rail and Truck Revised January 10, 2013 Facility Company Adjusted Adjusted Capacities Capacities Capacities Capacity Share HHI (MBD) (MBD) (MBD) (%) Contribution Col. 1 Col. 2 Col. 3 Col.4 Col. 5 Crude Oil Pipelines Kinder Morgan 300.0 300.0 77.1 11.2 125 Trans Mountain 300.0 Subtotal Crude Oil Pipelines 300.0 300.0 77.1 11.2 Existing Rail and Truck Canadian Pacific 11.0 11.0 11.0 1.6 3 Subtotal Existing Rail and Truck 11.0 11.0 11.0 1.6 Overseas Competitors Competitor 1 50.0 50.0 50.0 7.3 53 Competitor 2 50.0 50.0 50.0 7.3 53 Competitor 3 50.0 50.0 50.0 7.3 53 Competitor 4 50.0 50.0 50.0 7.3 53 Subtotal Overseas Competitors 200.0 200.0 200.0 29.0 Waterborne 401.1 401.1 401.1 58.2 * Total 912.1 912.1 689.2 100.0 2012 Vancouver Refinery Crude Oil Capacity (MBD) 55.0 2011 West Ridge Dock Deliveries (MBD) 44.2 Capacity- 338 2012 Pueet Sound Refine~ Crude Oil Ca~aci!Y {MBD) 590.0 Based HHI Total 689.2 Note: * Sum of extremely small shares squared, which essentially equals zero. Appendix to SEMI/SEPP 1.30 Adjusted Capacity Based HHI for the Vancouver Area and Puget Sound Crude Oil Destination Market 2017: Trans Mountain Expansion Completed; Excluding Potential Rail and Waterborne Entry Revised January 10, 2013 Facility Company Adjusted Adjusted Capacities Capacities Capacities Capacity Share HHI (MBD} (MBD} (MBD} (%} Contribution Col.1 Col.2 Col. 3 Col.4 Col.5 Crude Oil Pipelines Kinder Morgan 890.0 890.0 357.9 28.2 794 Trans Mountain 300.0 Trans Mountain Expansion 590.0 Subtotal Crude Oil Pipelines 890.0 890.0 357.9 28.2 Existing Rail and Truck Canadian Pacific 11.0 11.0 11.0 0.9 Subtotal Existing Rail and Truck 11.0 11.0 11.0 0.9 Overseas Competitors Competitor 1 50.0 50.0 50.0 3.9 16 Competitor 2 50.0 50.0 50.0 3.9 16 Competitor 3 50.0 50.0 50.0 3.9 16 Competitor 4 50.0 50.0 50.0 3.9 16 Competitor 5 50.0 50.0 50.0 3.9 16 Competitor 6 50.0 50.0 50.0 3.9 16 Competitor 7 50.0 50.0 50.0 3.9 16 Competitor 8 50.0 50.0 50.0 3.9 16 Competitor 9 50.0 50.0 50.0 3.9 16 Competitor 10 50.0 50.0 50.0 3.9 16 Subtotal Overseas Competitors 500.0 500.0 500.0 39.4 Waterborne 401.1 401.1 401.1 31.6 Total 1,802.1 1,802.1 1,270.0 100.0 2012 Vancouver Refinery Crude Oil Capacity (MBD) 55.0 2017 West Ridge Dock Deliveries (MBD) 625.0 Capacity- 590.0 950 2012 Puset Sound Refine!:Y Crude Oil Ca~aci!Y (MBD} Based HHI Total 1,270.0 Note: * Sum of extremely small shares squared, which essentially equals zero. Appendix to SEMI/SEPP 1.30 Adjusted Capacity Based HHI for the Vancouver Area and Puget Sound Crude Oil Destination Market 2017: Trans Mountain Expansion Completed; Including Potential Rail and Waterborne Entry Revised January 10, 2013 Facility Company Adjusted Adjusted Capacities Capacities Capacities Capacity Share HHI (MBD) (MBD) (MBD) (%) Contribution Col.1 Col. 2 Col. 3 Col.4 Col.5 Crude Oil Pipelines Kinder Morgan 890.0 890.0 288.9 22.7 517 Trans Mountain 300.0 Trans Mountain Expansion 590.0 Subtotal Crude Oil Pipelines 890.0 890.0 288.9 22.7 Potential Rail Entry Canadian National 30.0 30.0 30.0 2.4 6 Canadian Pacific 30.0 30.0 30.0 2.4 6 Subtotal Potential Rail Entry 60.0 60.0 60.0 4.7 Overseas Competitors Competitor 1 50.0 50.0 50.0 3.9 16 Competitor 2 50.0 50.0 50.0 3.9 16 Competitor 3 50.0 50.0 50.0 3.9 16 Competitor 4 50.0 50.0 50.0 3.9 16 Competitor 5 50.0 50.0 50.0 3.9 16 Competitor 6 50.0 50.0 50.0 3.9 16 Competitor 7 50.0 50.0 50.0 3.9 16 Competitor 8 50.0 50.0 50.0 3.9 16 Competitor 9 50.0 50.0 50.0. 3.9 16 Competitor 10 50.0 50.0 50.0 3.9 16 Subtotal Overseas Competitors 500.0 500.0 500.0 39.4 Waterborne Existing Waterborne 401.1 401.1 401.1 31.6 New Inbound Waterborne 20.0 20.0 20.0 1.6 Subtotal Waterborne 421.1 421.1 421.1 33.2 Total 1,871.1 1,871.1 1,270.0 100.0 2012 Vancouver Refinery Crude Oil Capacity (MBD) 55.0 2017 West Ridge Dock Deliveries (MBD) 625.0 Capacity- 2012 Puaet Sound Refine!l: Crude Oil (MBD} 590.0 684 Ca~aci~ Based HHI Total 1,270.0 Note: * Sum of extremely small shares squared, which essentially equals zero. Appendix 1 to SEMI/SEPP 1.30 Current, Expected, and Potential Competitors in the Western Canada Refined Petroleum Products Origin Market Revised January 10, 2013 I. 2011 Current Competitors A. Refined Products Pipelines 1. Kinder Morgan a. Trans Mountain 2. Enbridge a. Mainline B. Rail 1. Canadian National 2. Canadian Pacific II. Additional Competitors in 2017 A. Refined Products Pipelines 1. Kinder Morgan a. Trans Mountain Expansion Appendix 1 to SEMI/SEPP 1.30 Western Canada Refined Petroleum Products Origin Market Unadjusted Capacity Shares Revised January 10, 2013 Trans Mountain En bridge Unadjusted Unadjusted Date/ Market Events Capacity Share Capacity Share I. 2011 11.5% 19.2% (Current Situation) II. Future a. 2017 11.5% 19.2% (Trans Mountain Expansion Completed) Appendix 1 to SEMI/SEPP 1.30 Market Shares for the Western Canada Refined Products Origin Market 2011: Current Situation Revised January 10, 2013 Facility Company Share of Capacities Capacities Market {MBD) {MBD} {%) Col. 1 Col.2 Col. 3 Refined Products Pipelines Kinder Morgan 300.0 60.0 11.5 Trans Mountain 300.0 Enbridge 236.5 100.0 19.2 Mainline 236.5 Subtotal Refined Products Pipelines 536.5 160.0 30.8 Existing Rail Canadian National 20.0 20.0 3.8 Canadian Pacific 20.0 20.0 3.8 Subtotal Existing Rail 40.0 40.0 7.7 Consumption 319.7 319.7 61.5 Total 896.2 519.7 100.0 Appendix 1 to SEMI/SEPP 1.30 Western Canada Refined Petroleum Products Origin Market Adjusted Capacity HHis Revised Janual) Adjusted Date/ Market Events Capacity HHI I. 2011 303 (Current Situation) II. Future a. 2017 303 (Trans Mountain Expansion Completed) Appendix 1 to SEMI/SEPP 1.30 Adjusted Capacity Based HHI for the Western Canada Refined Petroleum Products Origin Market 2011: Current Situation Revised January 10, 2013 Facility Company Adjusted Adjusted Capacities Capacities Capacities Capacity Share HHI (MBD) (MBD) (MBD) (%) Contribution Col.1 Col.2 Col.3 Col.4 Col.5 Refined Products Pipelines Kinder Morgan 300.0 60.0 54.0 11.5 133 Trans Mountain 300.0 Enbridge 236.5 100.0 54.0 11.5 133 Mainline 236.5 Subtotal Refined Products Pipelines 536.5 160.0 107.9 23.1 Existing Rail Canadian National 20.0 20.0 20.0 4.3 18 Canadian Pacific 20.0 20.0 20.0 4.3 18 Subtotal Existing Rail 40.0 40.0 40.0 8.6 Consumption 319.7 319.7 319.7 68.4 * Total 896.2 519.7 467.6 100.0 Alberta and Saskatchewan Refinery Pipelineable Capacity- 467.6 303 Refined Petroleum Product Capacity Based HHI Appendix 1 to SEMI/SEPP 1.30 Adjusted Capacity Based HHI for the Western Canada Refined Petroleum Products Origin Market 2017: Trans Mountain Expansion Completed Revised January 10, 2013 Facility Company Adjusted Adjusted Capacities Capacities Capacities Capacity Share HHI {MBD} (MBD} {MBD} (%} Contribution Col.1 Col.2 Col. 3 Col.4 Col.5 Refined Products Pipelines Kinder Morgan 890.0 60.0 54.0 11.5 133 Trans Mountain 300.0 Trans Mountain Expansion 590.0 En bridge 236.5 100.0 54.0 11.5 133 Mainline 236.5 Subtotal Refined Products Pipelines 1 '126.5 160.0 107.9 23.1 Existing Rail Canadian National 20.0 20.0 20.0 4.3 18 Canadian Pacific 20.0 20.0 20.0 4.3 18 Subtotal Existing Rail 40.0 40.0 40.0 8.6 Consumption 319.7 319.7 319.7 68.4 * Total 1,486.2 519.7 467.6 100.0 Alberta and Saskatchewan Refinery Pipelineable Capacity- 467.6 303 Refined Petroleum Product Capacity Based HHI Appendix 1 to SEMI/SEPP 1.30 Current, Expected, and Potential Competitors in the Combined Kamloops and Vancouver Area Refined Petroleum Products Destination Market Revised January 10, 2013 I. 2011 Current Competitors A. Refined Products Pipelines 1. Kinder Morgan a. Trans Mountain B. Refineries 1. Chevron 2. Husky Oil Operations C. Rail 1. Canadian National 2. Canadian Pacific D. Waterborne II. Additional Competitors in 2017 A. Refined Products Pipelines 1. Kinder Morgan a. Trans Mountain Expansion Appendix 1 to SEMI/SEPP 1.30 Market Shares for the Kamloops and Vancouver Areas Refined Products Destination Market 2011: Current Situation Revised January 10, 2013 Facility Company Share of Capacities Capacities Market (MBQ) (MBD) (%) Col. 1 Col. 2 Col. 3 Refined Products Pipelines Kinder Morgan 300.0 60.0 29.2 Trans Mountain 300.0 Subtotal Refined Products Pipelines 300.0 60.0 29.2 Refineries Chevron 43.5 43.5 21.1 Husky Oil Operations 8.1 8.1 3.9 Subtotal Refineries 51.6 51.6 25.1 Existing Rail Canadian National 20.0 20.0 9.7 Canadian Pacific 20.0 20.0 9.7 Subtotal Existing Rail 40.0 40.0 19.4 Waterborne 54.1 54.1 26.3 Total 445.7 205.7 100.0 Appendix 1 to SEMI/SEPP 1.30 Market Shares for the Kamloops and Vancouver Areas Refined Products Destination Market 2017: Trans Mountain Expansion Completed Revised January 10, 201 ~ Facility Company Share of Capacities Capacities Market (MBD) (MBD) (%) Col. 1 Col. 2 Col. 3 Refined Products Pipelines Kinder Morgan 890.0 60.0 29.2 Trans Mountain 300.0 Trans Mountain Expansion 590.0 Subtotal Refined Products Pipelines 890.0 60.0 29.2 Refineries Chevron 43.5 43.5 21.1 Husky Oil Operations 8.1 8.1 3.9 Subtotal Refineries 51.6 51.6 25.1 Existing Rail Canadian National 20.0 20.0 9.7 Canadian Pacific 20.0 20.0 9.7 Subtotal Existing Rail 40.0 40.0 19.4 Waterborne 54.1 54.1 26.3 Total 1,035.7 205.7 100.0 Appendix 1 to SEMI/SEPP 1.30 Combined Kamloops and Vancouver Area Refined Petroleum Products Destination Market Adjusted Capacity HHis Revised Adjusted Date/ Market Events Capacity HHI I. 2011-2012 1,147 (Current Situation) II. Future a. 2017 1,147 (Trans Mountain Expansion Completed) APPENDIX 2 TO SEMI/SEPP 1.30 REVISED JANUARY 10, 2013 Appendix 2 to SEMI/SEPP 1.30 Revised January 10.2013 CAPP CANADIAN CRUDE OIL PRODUCTION FORECAST 2012-2030 June 2012 Notes: 1. CAPP allocates Saskatchewan Area Ill Medium crude as heavy crude. Also 17% of Area IV is > 900 kg/m3. 2. CAPP has revised from June 2007 report historical light/heavy ratio for Saskachewan starting in 2005. Appendix 2 to SEMI/SEPP 1.30 Revised January 10,2013 CAPP Canadian Crude Oil Supply Forecast 2012-2030 Blended Supply to Trunk Pipelines and Markets Thousand barrels per day Actua Forecast I I I I I I I • I I • I I: I • I I I I I I • I • I • I I: I • I I Total Light and Medium 570 606 702 739 782 814 827 835 834 832 827 820 810 800 789 777 763 744 724 708 690 Net Conventional Heavy to Market 309 312 323 320 321 317 316 313 307 305 303 298 292 289 287 287 283 280 276 274 272 TOTAL CONVENTIONAL 879 917 1,025 1,059 1,103 1,132 1,142 1,148 1,140 1,137 1,129 1,117 1,102 1,090 1,076 1,063 1,046 1,024 1,000 982 962 ,.,..~,.,. ~ M~ ,'- ..::;:~ ~~~ ,<" ... ~ ~ '<" ~' ~,· ..,- .. -- "---:.· '~ Upgraded Light (Synthetic)' 660 705 804 926 954 983 1,012 974 976 1,020 1,083 1,128 1,144 1,130 1,135 1,169 1,157 1,118 1,104 1,094 1,079 Oil Sands Heavy 2 1,134 1,296 1,310 1,483 1,647 1,775 1,971 2,173 2,304 2,496 2,734 2,932 3,178 3,386 3,661 3,947 4,041 4.276 4,481 4,618 4.830 TOTAL OIL SANDS AND UPGRADERS 1,794 2,001 2,115 2,409 2,601 2,758 2,983 3,147 3,280 3,516 3,817 4,060 4,322 4,516 4,796 5,116 5,199 5,394 5,585 5,712 5,909 Total Light Supply 1,229 1,311 1,506 1 ,665 1 '736 1,797 1,839 1,809 1,809 1,852 1,909 1,948 1,954 1,931 1,924 1,945 1,920 1,862 1,828 1,802 1,769 Total Heav Su I 1 444 1608 1 633 1 803 1 968 2092 2287 2486 2611 2801 3 037 3229 3470 3.675 3947 4233 4325 4556 4,757 4893 5102 WESTERN CANADA OIL SUPPLY 2,673 2,918 3,139 3,468 3,705 3,890 4,125 4,295 4,420 4,653 4,946 5,177 5,424 5,606 5,871 6,179 6,244 6,418 6,585 6,695 6,870 Notes: 1 Includes upgraded conventional APPENDIX 3 TO SEMI/SEPP 1.30 REVISED JANUARY 10, 2013 Appendix 3 to SEMI/SEPP 1.30 Revised January 10, 2013 British Columbia Regional District and Municipal Population Estimates Area 2010-2011 SGC Name Type 2006 2007 2008 2009 2010 2011 %Change 23000 Alberni-Ciayoquot RD 31,078 31,141 31,439 31,580 31,626 31,664 0.1 23008 PortAiberni C' 17,615 17,624 17,681 17,763 17,747 17,836 0.5 23025 Tofino DM 1,750 1,773 1,812 1,831 1,894 1,922 1.5 23019 Ucluelet DM 1,522 1,545 1,577 1,593 1,605 1,634 1.8 23999 Unincorporated Areas RDR 10,191 10,199 10,369 10,393 10,380 10,272 -1.0 51000 Bulkley-Nechako RD 38,866 38,474 38,788 38,908 39,171 39,371 0.5 51022 Burns Lake VL 2,154 2,164 2,149 2,117 2,142 2,116 -1.2 51013 FortS!. James DM 1,362 1,362 1,343 1,323 1,295 1,339 3.4 51009 Fraser Lake VL 1,129 1,135 1,119 1,123 1,160 1,172 1.0 51032 Gran isle VL 365 377 390 396 396 389 -1.8 51034 Houston DM 3,197 3,062 3,007 2,962 3,007 3,039 1.1 51043 Smithers T 5,292 5,207 5,288 5,328 5,407 5,347 -1.1 51038 Telkwa VL 1,333 1,332 1,359 1,359 1,402 1,441 2.8 51007 Vanderhoof DM 4,172 4,144 4,123 4,148 4,047 4,114 1.7 51999 Unincorporated Areas RDR 19,862 19,691 20,010 20,152 20,315 20,414 0.5 17000 Capital RD 355,872 359,304 364,107 368,024 372,230 374,675 0.7 17015 Central Saanich DM 16,006 16,024 16,171 16,190 16,197 16,183 -0.1 17041 Colwood c 15,260 15,582 15,948 16,194 16,574 16,721 0.9 17040 Esquimalt DM 17,513 17,528 17,661 17,704 17,684 17,654 -0.2 17049 Highlands DM 2,010 2,036 2,115 2,178 2,256 2,293 1.6 17044 Langford c 23,513 24,766 26,123 27,362 29,150 30,263 3.8 17042 Metchosin DM 4,969 5,061 5,108 5,139 5,306 5,326 0.4 17005 North Saanich DM 10,923 10,875 11,045 11,034 11,108 11,128 0.2 17030 Oak Bay DM 18,040 17,971 18,070 18,035 18,006 18,024 0.1 17021 Saanich DM 111,575 112,072 113,203 113,656 114,107 113,999 -0.1 17010 Sidney T 11,510 11,552 11,551 11,592 11,597 11,583 -0.1 17052 Sooke DM 10,077 10,334 10,414 10,553 10,873 10,919 0.4 17034 Victoria c 80,871 81,657 81,890 82,886 83,338 84,031 0.8 17047 View Royal T 9,126 9,171 9,355 9,595 9,740 9,838 1.0 17999 Unincorporated Areas RDR 24,479 24,675 25,453 25,906 26,294 26,713 1.6 41000 Cariboo RD 63,217 63,442 64,585 65,125 65,450 65,847 0.6 41005 1oo Mile House DM 1,912 1,919 1,933 1,943 1,954 1,974 1.0 41013 Quesnel C' 9,475 9,504 9,627 9,722 9,743 9,947 2.1 41025 Wells DM 236 244 257 257 278 304 9.4 41009 Williams Lake C' 11,082 11,107 11,144 11,103 10,998 11,006 0.1 41999 Unincorporated Areas RDR 40,512 40,668 41,624 42,100 42,477 42,616 0.3 45000 Central Coast RD 3,220 3,169 3,120 3,122 3,174 3,182 0.3 3000 Central Kootenay RD 56,488 57,619 58,989 59,829 60,362 60,681 0.5 3045 Castlegar c 7,360 7,510 7,631 7,881 7,877 7,911 0.4 3004 Creston T 4,837 4,988 5,193 5,252 5,244 5,224 -0.4 3023 Kaslo VL 1,073 1,167 1,170 1,186 1,183 1,184 0.1 3050 Nakusp VL 1,524 1,512 1,523 1,532 1,536 1,532 -0.3 3015 Nelson C' 9,327 9,475 9,803 9,951 9,791 9,804 0.1 3032 New Denver VL 512 503 526 517 510 515 1.0 3011 Salmo VL 1,008 1,027 1,048 1,061 1,070 1,073 0.3 3027 Silverton VL 186 192 198 202 205 203 -1.0 3019 Slocan VL 314 345 369 391 397 399 0.5 3999 Unincorporated Areas RDR 30,347 30,900 31,528 31,856 32,549 32,836 0.9 35000 Central Okanagan RD 167,417 173,745 180,328 184,662 185,389 187,234 1.0 35010 Kelowna c' 110,351 114,670 118,685 120,961 121,271 121,846 0.5 35016 Lake Country DM 9,790 10,221 11,009 11,423 11,509 11,799 2.5 35018 Peachland DM 4,938 5,113 5,222 5,250 5,170 5,160 -0.2 35029 West Kelowna DM' na na 27,169 27,267 27,235 27,408 0.6 35999 Unincorporated Areas RDR 42,338 43,741 18,243 19,761 20,204 21,021 4.0 39000 Columbia-Shuswap RD 50,725 51,593 53,182 53,780 53,664 53,748 0.2 39007 Golden T 3,876 3,858 3,914 3,964 3,934 3,934 0.0 39019 Revelstoke c' 7,288 7,273 7,268 7,276 7,269 7,329 0.8 39032 Salmon Arm c 16,305 16,652 17,046 17,242 17,123 17,246 0.7 39045 Sicamous DM 2,684 2,750 2,939 2,953 2,962 2,913 -1.7 39999 Unincorporated Areas RDR 20,572 21,060 22,015 22,345 22,376 22,326 -0.2 26000 Comox Regional District (See N RD4 na na 63,373 64,163 64,623 64,805 0.3 26005 Comox T' na na 13,265 13,460 13,640 13,493 -1.1 26010 Courtenay C' na na 23,981 24,246 24,582 24,967 1.6 26014 Cumberland VL na na 3,045 3,167 3,252 3,311 1.8 Appendix 3 to SEMI/SEPP 1.30 Revised January 10, 2013 26999 Unincorporated Areas RDR4 na na 23,082 23,290 23,149 23,034 -0.5 25000 Comox-Strathcona {See Notes) RD4 103,129 104,927 na na na na na 25034 Campbell River c' 30,054 30,447 na na na na na 25005 Comox T' 12,401 12,721 na na na na na 25010 Courtenay c' 22,481 23,369 na na na na na 25014 Cumberland VL 2,765 2,880 na na na na na 25025 Gold River VL 1,371 1,411 na na na na na 25039 Sayward VL 341 326 na na na na na 25030 Tahsis VL 366 354 na na na na na 25029 Zeballos VL 189 182 na na na na na 25999 Unincorporated Areas RDR 33,161 33,237 na na na na na 19000 Cowichan Valley RD 78,471 79,564 80,971 81,790 82,846 83,300 0.5 19012 Duncan c 5,035 4,978 4,995 5,014 4,985 4,900 ·1.7 19021 Ladysmith T' 7,637 7,899 8,066 8,128 8,240 8,328 1.1 19016 Lake Cowichan T' 2,973 2,962 3,025 3,186 3,183 3,140 -1.4 19008 North Cowichan DM 28,408 28,801 29,249 29,530 29,828 30,125 1.0 19999 Unincorporated Areas RDR 34,418 34,924 35,636 35,932 36,610 36,807 0.5 1000 East Kootenay RD 56,097 57,043 58,799 60,039 60,251 60,301 0.1 1043 Canal Flats VL 701 747 783 818 826 813 -1.6 1022 Cranbrook C' 18,493 18,585 18,938 19,185 19,117 18,932 -1.0 1003 Elkford DM 2,517 2,518 2,559 2,606 2,705 2,730 0.9 1012 Fernie C' 4,289 4,293 4,367 4,420 4,409 4,458 1.1 1039 lnvermere DM 3,046 3,184 3,465 3,672 3,617 3,653 1.0 1028 Kimberley c 6,184 6,323 6,523 6,713 6,646 6,683 0.6 1040 Radium Hot Springs VL 738 892 973 1,006 1,015 1,028 1.3 1006 Sparwood DM 3,680 3,704 3,780 3,809 3,770 3,778 0.2 1999 Unincorporated Areas RDR 16,449 16,797 17,411 17,810 18,146 18,226 0.4 9000 Fraser Valley RD 266,727 271,284 276,316 280,554 284,913 286,981 0.7 9052 Abbotsford C' 129,345 131,250 133,547 136,031 138,139 139,343 0.9 9020 Chilliwack c 71,298 73,300 74,943 76,200 77,953 78,898 1.2 9027 Harrison Hot Springs VL 1,578 1,584 1,597 1,596 1,597 1,597 0.0 9009 Hope DM 6,243 6,161 6,203 6,277 6,320 6,201 -1.9 9032 Kent DM 5,318 5,341 5,461 5,522 5,578 5,535 -0.8 9056 Mission DM 35,741 36,283 36,758 37,213 37,563 37,372 ·0.5 9999 Unincorporated Areas RDR 17,204 17,365 17,807 17,715 17,763 18,035 1.5 53000 Fraser-Fort George RD 94,416 94,918 95,402 95,769 96,548 96,928 0.4 53033 Mackenzie DM 4,616 4,534 4,255 3,831 3,705 3,738 0.9 53012 McBride VL 661 659 678 675 677 697 3.0 53023 Prince George c 72,890 73,346 73,899 74,639 75,546 75,828 0.4 53007 Valemount VL 1,018 1,007 1,015 1,045 1,062 1,070 0.8 53999 Unincorporated Areas RDR 15,231 15,372 15,555 15,579 15,558 15,595 0.2 15000 Greater Vancouver RD 2,199,124 2,237,211 2,272,977 2,320,576 2,373,941 2,404,911 1.3 15038 An more VL 1,887 2,030 2,122 2,162 2,202 2,265 2.9 15036 Belcarra VL 688 679 688 682 690 689 -0.1 15062 Bowen Island IM 3,468 3,522 3,582 3,613 3,677 3,716 1.1 15025 Burnaby c 210,507 214,938 218,440 223,076 227,323 229,464 0.9 15034 Coquitlam c 119,582 120,260 121,574 123,362 126,558 127,785 1.0 15011 Delta DM 99,490 99,302 99,523 99,984 99,971 100,094 0.1 15002 Langley, City of c 24,899 25,169 25,388 25,557 25,850 26,119 1.0 15001 Langley District Municipality DM 96,792 99,020 101,435 103,394 104,666 105,747 1.0 15065 Lions Bay VL 1,406 1,403 1,398 1,400 1,394 1,408 1.0 15075 Maple Ridge DM 71,453 72,508 73,988 75,143 76,396 77,402 1.3 15029 New Westminster c 60,533 61,783 63,783 65,096 66,873 67,880 1.5 15051 North Vancouver, City of c 46,910 47,282 47,783 48,941 50,711 51,083 0.7 15046 North Vancouver District Munici DM 85,472 85,974 86,114 86,832 88,345 88,678 0.4 15070 Pitt Meadows C' 16,297 16,584 17,434 17,937 18,131 18,355 1.2 15039 Port Coquitlam c 54,538 54,976 55,574 56,516 57,414 57,646 0.4 15043 Port Moody c 28,747 29,947 31,511 33,039 33,923 34,488 1.7 15015 Richmond c 182,652 186,395 189,064 193,491 196,801 197,631 0.4 15004 Surrey c 412,734 422,915 434,583 447,106 462,211 473,238 2.4 15022 Vancouver c 599,765 609,974 615,888 628,600 642,657 651,048 1.3 15055 West Vancouver DM 42,863 42,977 42,915 43,361 44,046 44,096 0.1 15007 White Rock c 18,916 18,998 18,901 19,126 19,272 19,313 0.2 15999 Unincorporated Areas RDR 19,525 20,575 21,289 22,158 24,830 26,766 7.8 49000 Kitimat-Stikine RD" 38,803 38,322 39,131 39,476 39,632 39,702 0.2 49022 Hazelton VL 293 296 298 305 302 314 4.0 49005 Kitimat DM 9,328 9,096 9,182 9,238 9,176 9,098 -0.9 49024 New Hazelton DM 627 610 611 605 603 617 2.3 49032 Stewart DM 496 481 510 491 495 499 0.8 49011 Terrace c 11,475 11,358 11,553 11,689 11,927 12,044 1.0 49999 Unincorporated Areas RDR' 16,584 16,481 16,977 17,148 17,129 17,130 0.0 Appendix 3 to SEMI/SEPP 1.30 Revised January 10, 2013 5000 Kootenay-Boundary RD 30,826 31,393 32,018 32,150 31,877 31,851 -0.1 5005 Fruitvale VL 1,968 2,010 2,049 2,034 2,012 2,022 0.5 5032 Grand Forks c 4,059 4,104 4,184 4,155 3,997 3,917 -2.0 5042 Greenwood c 625 633 668 677 685 692 1.0 5037 Midway VL 621 643 662 658 663 669 0.9 5009 Montrose VL 1,018 1,023 1,046 1,044 1,046 1,047 0.1 5023 Ross land c 3,278 3,333 3,476 3,536 3,553 3,563 0.3 5014 Trail c 7,248 7,366 7,365 7,362 7,240 7,260 0.3 5018 Warfield VL 1,739 1,794 1,799 1,813 1,808 1,801 -0.4 5999 Unincorporated Areas RDR 10,270 10,487 10,769 10,871 10,873 10,880 0.1 43000 Mount Waddington RD 11,962 11,915 11,956 12,058 12,051 12,034 -0.1 43008 Alert Bay VL 477 476 487 479 485 485 0.0 43017 Port Alice VL 828 841 843 843 842 837 -0.6 43023 Port Hardy DM 3,976 3,925 3,933 3,991 3,949 3,917 -0.8 43012 Port McNeill T 2,681 2,655 2,605 2,622 2,647 2,633 -0.5 43999 Unincorporated Areas RDR 4,000 4,018 4,088 4,123 4,128 4,162 0.8 21000 Nanaimo RD 141,246 143,008 145,891 148,D42 149,670 150,632 0.7 21008 Lanzville DM 3,685 3,721 3,745 3,701 3,688 3,641 -1.3 21007 Nanaimo c 80,757 81,464 82,763 84,331 85,487 86,961 1.7 21018 Parksville c 11,090 11,315 11,617 11,798 11,828 11,584 -2.1 21023 Qualicum Beach T 8,516 8,619 8,754 8,776 8,727 8,646 -0.9 21999 Unincorporated Areas RDR 37,198 37,889 39,012 39,436 39,940 39,800 -0.3 37000 North Okanagan RD 78,877 80,118 81,819 83,260 83,115 83,052 -0.1 37028 Armstrong c 4,342 4,350 4,468 4,539 4,513 4,413 ·2.2 37010 Goldstream DM 9,674 9,904 10,155 10,402 10,286 10,319 0.3 37033 Enderby c 2,845 2,869 2,890 2,910 2,923 2,936 0.4 37005 Lumby VL' 1,658 1,710 1,754 1,806 1,815 1,863 2.6 37024 Spallumcheen DM 4,991 4,983 5,017 5,135 5,152 5,155 0.1 37014 Vernon C' 36,922 37,554 38,348 39,016 38,883 38,990 0.3 37999 Unincorporated Areas RDR 18,445 18,748 19,187 19,452 19,543 19,376 -0.9 59000 Northern Rockies (See Notes) RD 6,298 6,125 6,062 6,010 6,207 6,324 1.9 59005 Fort Nelson T' 4,612 4,457 4,399 na na na na 59007 Northern Rockies Regional Mur RGM< na na na 5,565 5,742 5,855 2.0 59999 Unincorporated Areas RDR' 1,686 1,668 1,663 445 465 469 0.9 7000 Okanagan-Similkameen RD 80,351 81,329 82,388 83,474 82,735 82,644 -0.1 7009 Keremeos VL 1,289 1,325 1,462 1,514 1,516 1,531 1.0 7014 Oliver T' 4,374 4,450 4,594 4,788 4,549 4,478 -1.6 7005 Osoyoos T 4,790 4,928 5,045 5,196 5,201 5,210 0.2 7041 Penticton c 32,544 32,857 32,980 33,291 33,068 33,098 0.1 7024 Princeton T 2,685 2,696 2,722 2,761 2,994 3,073 2.6 7035 Summerland DM 10,911 11,013 11,143 11,257 11,004 10,942 -0.6 7999 Unincorporated Areas RDR 23,758 24,060 24,442 24,667 24,403 24,312 -0.4 55000 Peace River RD 59,330 60,220 61,005 62,290 63,351 64,280 1.5 55010 Chetwynd DM 2,722 2,638 2,640 2,680 2,713 2,706 -0.3 55014 Dawson Creek C' 11,094 11,290 11,422 11,528 11,856 12,257 3.4 55034 Fort St. John c 17,933 18,394 18,796 19,481 19,867 20,408 2.7 55025 Hudson's Hope DM 1,012 1,009 1,031 1,052 1,056 1,055 -0.1 55005 Pouce Coupe VL' 738 744 738 747 792 804 1.5 55030 Taylor DM 1,386 1,403 1,469 1,483 1,497 1,501 0.3 55003 Tumbler Ridge DM 2,491 2,434 2,441 2,421 2,428 2,436 0.3 55999 Unincorporated Areas RDR 21,954 22,308 22,468 22,898 23,142 23,113 -0.1 27000 Powell River RD 19,694 19,793 20,029 20,232 20,449 20,525 0.4 27008 Powell River c 13,027 13,145 13,285 13,355 13,570 13,597 0.2 27806 Sechelt lnd Gov Dist (Part) IGD" 17 17 18 18 18 18 0.0 27999 Unincorporated Areas RDR 6,650 6,631 6,726 6,859 6,861 6,910 0.7 47000 Skeena-Queen Charlotte RD 19,981 19,757 19,625 19,462 19,492 19,482 -0.1 47023 Masset VL 947 937 913 930 920 924 0.4 47030 Port Clements VL 443 450 461 454 456 457 0.2 47007 Port Edward DM 581 577 585 571 571 566 -0.9 47012 Prince Rupert c 13,072 12,907 12,832 12,862 12,990 12,935 -0.4 47026 Village of Queen Charlott VL 950 951 952 962 959 952 -0.7 47999 Unincorporated Areas RDR 3,988 3,935 3,882 3,683 3,596 3,648 1.4 31000 Squamish-Lillooet RD 36,628 37,129 37,853 39,257 40,344 41,379 2.6 31026 Lillooet DM 2,355 2,318 2,373 2,370 2,367 2,367 0.0 31012 Pemberton VL 2,349 2,359 2,339 2,419 2,437 2,399 -1.6 31006 Squamish DM 15,495 15,982 16,586 17,202 17,892 18,712 4.6 31020 Whistler RM' 9,796 9,750 9,688 10,241 10,528 10,437 -0.9 31999 Unincorporated Areas RDR 6,633 6,720 6,867 7,025 7,120 7,464 4.8 57000 Stikine R" 1,130 1,152 675 644 614 581 -5.4 Appendix 3 to SEMI/SEPP 1.30 Revised January 10, 2013 24000 Strathcona Regional Dist. (See I RD4 na na 43,796 44,244 44,373 44,498 0.3 24034 Campbell River C' na na 31,006 31,367 31,571 31,771 0.6 24025 Gold River VL na na 1,425 1,426 1,410 1,386 -1.7 24039 Sayward VL na na 329 332 334 339 1.5 24030 Tahsis VL na na 380 381 380 372 -2.1 24029 Zeballos VL na na 174 162 166 171 3.0 24999 Unincorporated Areas RDR4 na na 10,482 10,576 10,512 10,459 -0.5 29000 Sunshine Coast RD 27,959 28,592 29,202 29,588 29,975 30,357 1.3 29005 Gibsons T 4,212 4,336 4,361 4,453 4,414 4,450 0.8 29011 Sechell DM 8,501 8,767 9,017 9,176 9,494 9,727 2.5 29803 Sechelt lnd Gov Dist (Part) IGD"' 827 814 815 832 827 807 -2.4 29999 Unincorporated Areas RDR 14,419 14,675 15,009 15,127 15,240 15,373 0.9 33000 Thompsen-Nicola RD 125,648 127,345 130,221 131,839 131,601 132,352 0.6 33019 Ashcroft VL 1,671 1,722 1,741 1,742 1,755 1,756 0.1 33074 Bariere DM~ na na 1,725 1,723 1,712 1,693 -1.1 33024 Cache Creek VL 1,045 1,058 1,085 1,085 1,084 1,087 0.3 33054 Chase VL 2,439 2,409 2,469 2,481 2,487 2,497 0.4 33067 ClearWater DM~ na na 2,382 2,364 2,355 2,314 -1.7 33028 Clinton VL 578 573 597 598 603 609 1.0 33042 Kamloops C' 83,129 84,383 86,200 87,124 87,085 87,654 0.7 33035 Logan Lake DM 2,198 2,194 2,198 2,193 2,207 2,215 0.4 33015 Lytton VL 235 231 226 226 226 224 -0.9 33006 Merritt c 7,338 7,393 7,455 7,460 7,283 7,230 -0.7 33045 Sun Peaks Mountain VL' na na na na 396 405 2.3 33999 Unincorporated Areas RDR 27,015 27,382 24,143 24,843 24,408 24,668 1.1 British Columbia 4,243,580 4,309,632 4,384,047 4,459,947 4,529,674 4,573,321 1.0 Source: Demographic Analysis Section, BC Slats Ministry of Citizens' Services Government of British Columbia Dec/2011 Notes: RD = Regional District, R =Region, RDR = Regional District Unincorporated Area, RM = Resort Municipality, /GO = Indian Government District, C = City, T = Town, VL = Village, OM= District Municipality, IM = Island Municipality, RGM =Regional Municipality. All figures correspond to municipal boundaries as of July 1st of the year stated. All figures are as of July 1st of the year stated. SGC =Standard Geographical Classification 1 Denotes a boundary or status change between July 1, 2006 and June 30, 2011. " New incorporations: Clearwater on Dec 3, 2007; Barriere on Dec 4, 2007; West Ke/owna (formerly Westside) on Dec 6, 2007; Northern Rockies Regional Municipality on Feb 6, 2009; Sun Peaks Resort Municipality on Jun 28, 2010. " The Seche/t Indian Government District is split between two Regional Districts, thus the two table occurrences here. 4 Comox Strathcona RD split into Comox RD and Strathcona RD Feb 15, 2008. 0 Dease Lake area incorporated into Kitimat-Stikine RD (from Stikine) on June 21, 2007. Appendix 3 to SEM 1/SEPP 1.30 Revised January 10. 2013 British Columbia Development Region and Regional District Population Estimates Area 2010-2011 SGC Name Type 2006 2007 2008 2009 2010 2011 %Change Vancouver Island/Coast 744,672 752,821 764,682 773,255 781,042 785,315 0.6 23000 Alberni-Ciayoquot RD 31.078 31.141 31,439 31,580 31,626 31,664 0.1 17000 Capital RD 355,872 359,304 364,107 368,024 372,230 374,675 0.7 45000 Central Coast RD 3,220 3,169 3,120 3,122 3,174 3,182 0.3 26000 Comox Regional District (See Notes) RD 1 na na 63,373 64,163 64,623 64,805 0.3 25000 Comox-Strathcona (See Notes) RD 1 103,129 104,927 na na na na na 19000 Cowichan Valley RD 78,471 79,564 80,971 81,790 82,846 83,300 0.5 43000 Mount Waddington RD 11,962 11,915 11,956 12,058 12,051 12,034 -0.1 21000 Nanaimo RD 141,246 143,008 145,891 148,042 149,670 150,632 0.7 27000 Powell River RD 19,694 19,793 20,029 20,232 20,449 20,525 0.4 24000 Strathcona Regional Dist. (See Notes) RD 1 na na 43,796 44,244 44,373 44,498 0.3 Mainland/Southwest 2,530,438 2,574,216 2,616,348 2,669,975 2,729,173 2,763,628 1.3 9000 Fraser Valley RD 266,727 271,284 276,316 280,554 284,913 286,981 0.7 15000 Greater Vancouver RD 2,199,124 2,237,211 2,272,977 2,320,576 2,373,941 2,404,911 1.3 31000 Squamish-Lillooet RD 36,628 37,129 37,853 39,257 40,344 41,379 2.6 29000 Sunshine Coast RD 27,959 28,592 29,202 29,588 29,975 30,357 1.3 Thompson/Okanagan 503,018 514,130 527,938 537,015 536,504 539,030 0.5 35000 Appendix 2 to SEMI/SEPP 1.30 Revisec RD 167,417 173,745 180,328 184,662 185,389 187,234 1.0 39000 Columbia-Shuswap RD 50,725 51,593 53,182 53,780 53,664 53,748 0.2 37000 North Okanagan RD 78,877 80,118 81,819 83,260 83,115 83,052 -0.1 7000 Okanagan-Similkameen RD 80,351 81,329 82,388 83,474 82,735 82,644 -0.1 33000 Thompson-Nicola RD 125,648 127,345 130,221 131,839 131,601 132,352 0.6 Kootenay 143,411 146,055 149,806 152,018 152,490 152,833 0.2 3000 Central Kootenay RD 56,488 57,619 58,989 59,829 60,362 60,681 0.5 1 ooo East Kootenay RD 56,097 57,043 58,799 60,039 60,251 60,301 0.1 5000 Kootenay-Boundary RD 30,826 31,393 32,018 32,150 31,877 31,851 -0.1 Cariboo 157,633 158,360 159,987 160,894 161,998 162,775 0.5 41 000 Cariboo RD 63,217 63,442 64,585 65,125 65,450 65,847 0.6 53000 Fraser-Fort George RD 94,416 94,918 95,402 95,769 96,548 96,928 0.4 North Coast 58,784 58,079 58,756 58,938 59,124 59,184 0.1 49000 Kitimat-Stikine RD2 38,803 38,322 39,131 39,476 39,632 39,702 0.2 47000 Skeena-Queen Charlotte RD 19,981 19,757 19,625 19,462 19,492 19,482 -0.1 Nechako 39,996 39,626 39,463 39,552 39,785 39,952 0.4 51 ooo Bulkley-Nechako RD 38,866 38,474 38,788 38,908 39,171 39,371 0.5 57000 Stikine R2 1,130 1,152 675 644 614 581 -5.4 Northeast 65,628 66,345 67,067 68,300 69,558 70,604 1.5 59000 Northern Rockies RD 6,298 6,125 6,062 6,010 6,207 6,324 1.9 55000 Peace River RD 59,330 60,220 61,005 62,290 63,351 64,280 1.5 British Columbia 4,243,580 4,309,632 4,384,047 4,459,947 4,529,674 4,573,321 1.0 Source: Demographic Analysis Section, BC Slats Ministry of Citizens' SeNices Government of British Columbia Dec, 2011 Notes: DR=Development Region, RD =Regional District, R =Region All figures correspond to municipal boundaries as of July 1st of the year stated. All figures are as of July 1st of the year stated. SGC =Standard Geographical Classification 1 Comox Strathcona RD split into Comox RD and Strathcona RD Feb 15, 2008. 2 Dease Lake area incorporated into Kitimat-Stikine RD (from Stikine) on June 21, 2007. Appendix 3 to SEMI/SEPP 1.30 Revised January 10, 2013 British Columbia Development Region and Municipal Population Estimates Area 2010-2011 SGC Name Type 2006 2007 2008 2009 2010 2011 %Change Vancouver Island/Coast 744,672 752,821 764,682 773,255 781,042 785,315 0.6 17021 Saanich DM 111,575 112,072 113,203 113,656 114,107 113,999 -0.1 21007 Nanaimo c 80,757 81,464 82,763 84,331 85,487 86,961 1.7 17034 Victoria c 80,871 81,657 81,890 82,886 83,338 84,031 0.8 24034 Campbell River C' 30,054 30,447 31,006 31,367 31,571 31,771 0.6 17044 Langford c 23,513 24,766 26,123 27,362 29,150 30,263 3.8 19008 North Cowichan DM 28,408 28,801 29,249 29,530 29,828 30,125 1.0 26010 Courtenay C' 22,481 23,369 23,981 24,246 24,582 24,967 1.6 17030 Oak Bay DM 18,040 17,971 18,070 18,035 18,006 18,024 0.1 23008 PortAiberni C' 17,615 17,624 17,681 17,763 17,747 17,836 0.5 17040 Esquimalt DM 17,513 17,528 17,661 17,704 17,684 17,654 -0.2 17041 Colwood c 15,260 15,582 15,948 16,194 16,574 16,721 0.9 17015 Central Saanich DM 16,006 16,024 16,171 16,190 16,197 16,183 -0.1 27008 Powell River c 13,027 13,145 13,285 13,355 13,570 13,597 0.2 26005 Com ox T' 12,401 12,721 13,265 13,460 13,640 13,493 -1.1 21018 Parksville c 11,090 11,315 11,617 11,798 11,828 11,584 -2.1 17010 Sidney T 11,510 11,552 11,551 11,592 11,597 11,583 -0.1 17005 North Saanich DM 10,923 10,875 11,045 11,034 11,108 11,128 0.2 17052 Sooke DM 10,077 10,334 10,414 10,553 10,873 10,919 0.4 17047 View Royal T 9,126 9,171 9,355 9,595 9,740 9,838 1.0 21023 Qualicum Beach T 8,516 8,619 8,754 8,776 8,727 8,646 -0.9 19021 Ladysmith T' 7,637 7,899 8,066 8,128 8,240 8,328 1.1 17042 Metchosin DM 4,969 5,061 5,108 5;139 5,306 5,326 0.4 19012 Duncan c 5,035 4,978 4,995 5,014 4,985 4,900 -1.7 43023 Port Hardy DM 3,976 3,925 3,933 3,991 3,949 3,917 -0.8 21008 Lanzville DM 3,685 3,721 3,745 3,701 3,688 3,641 -1.3 26014 Cumberland VL 2,765 2,880 3,045 3,167 3,252 3,311 1.8 19016 Lake Cowichan T' 2,973 2,962 3,025 3,186 3,183 3,140 -1.4 43012 Port McNeill T 2,681 2,655 2,605 2,622 2,647 2,633 -0.5 17049 Highlands DM 2,010 2,036 2,115 2,178 2,256 2,293 1.6 23025 Totino DM 1,750 1,773 1,812 1,831 1,894 1,922 1.5 23019 Ucluelet DM 1,522 1,545 1,577 1,593 1,605 1,634 1.8 24025 Gold River VL 1,371 1,411 1,425 1,426 1,410 1,386 -1.7 43017 Port Alice VL 828 841 843 843 842 837 -0.6 43008 Alert Bay VL 477 476 487 479 485 485 0.0 24030 Tahsis VL 366 354 380 381 380 372 -2.1 24039 Sayward VL 341 326 329 332 334 339 1.5 24029 Zeballos VL 189 182 174 162 166 171 3.0 27806 Sechelt lnd Gov Dist (Part) IGD" 17 17 18 18 18 18 0.0 4 Unincorporated Areas RDR 153,317 154,742 157,968 159,637 161,048 161,339 0.2 Mainland/Southwest 2,530,438 2,574,216 2,616,348 2,669,975 2,729,173 2,763,628 1.3 15022 Vancouver c 599,765 609,974 615,888 628,600 642,657 651,048 1.3 15004 Surrey c 412,734 422,915 434,583 447,106 462,211 473,238 2.4 15025 Burnaby c 210,507 214,938 218,440 223,076 227,323 229,464 0.9 15015 Richmond c 182,652 186,395 189,064 193,491 196,801 197,631 0.4 9052 Abbotsford C' 129,345 131,250 133,547 136,031 138,139 139,343 0.9 15034 Coquitlam c 119,582 120,260 121,574 123,362 126,558 127,785 1.0 15001 Langley District Municipality OM 96,792 99,020 101,435 103,394 104,666 105,747 1.0 15011 Delta DM 99,490 99,302 99,523 99,984 99,971 100,094 0.1 North Vancouver District 15046 Municipality DM 85,472 85,974 86,114 86,832 88,345 88,678 0.4 9020 Chilliwack c 71,298 73,300 74,943 76,200 77,953 78,898 1.2 15075 Maple Ridge DM 71,453 72,508 73,988 75,143 76,396 77,402 1.3 15029 New Westminster c 60,533 61,783 63,783 65,096 66,873 67,880 1.5 15039 Port Coquitlam c 54,538 54,976 55,574 56,516 57,414 57,646 0.4 15051 North Vancouver, City of c 46,910 47,282 47,783 48,941 50,711 51,083 0.7 15055 West Vancouver DM 42,863 42,977 42,915 43,361 44,046 44,096 0.1 9056 Mission DM 35,741 36,283 36,758 37,213 37,563 37,372 -0.5 15043 Port Moody c 28,747 29,947 31,511 33,039 33,923 34,488 1.7 15002 Langley, City of c 24,899 25,169 25,388 25,557 25,850 26,119 1.0 15007 White Rock c 18,916 18,998 18,901 19,126 19,272 19,313 0.2 31006 Squamish DM 15,495 15,982 16,586 17,202 17,892 18,712 4.6 15070 Pitt Meadows C' 16,297 16,584 17,434 17,937 18,131 18,355 1.2 31020 Whistler RM' 9,796 9,750 9,688 10,241 10,528 10,437 -0.9 29011 Sechelt DM 8,501 8,767 9,017 9,176 9,494 9,727 2.5 9009 Hope DM 6,243 6,161 6,203 6,277 6,320 6,201 -1.9 9032 Kent DM 5,318 5,341 5,461 5,522 5,578 5,535 -0.8 29005 Gibsons T 4,212 4,336 4,361 4,453 4,414 4,450 0.8 15062 Bowen Island IM 3,468 3,522 3,582 3,613 3,677 3,716 1.1 31012 Pemberton VL 2,349 2,359 2,339 2,419 2,437 2,399 -1.6 31026 Lillooet DM 2,355 2,318 2,373 2,370 2,367 2,367 0.0 15038 An more VL 1,887 2,030 2,122 2,162 2,202 2,265 2.9 Appendix 3 to SEMI/SEPP 1.30 Revised January 10, 2013 9027 Harrison Hot Springs VL 1,578 1,584 1,597 1,596 1,597 1,597 0.0 15065 Lions Bay VL 1,406 1,403 1,398 1,400 1,394 1,408 1.0 29803 Sechelt lnd Gov Dist (Part) IGDj 827 814 815 832 827 807 -2.4 15036 Belcarra VL 688 679 688 682 690 689 -0.1 Unincorporated Areas RDR 57,781 59,335 60,972 62,025 64,953 67,638 4.1 Thompson/Okanagan 503,018 514,130 527,938 537,015 536,504 539,030 0.5 35010 Kelowna C' 110,351 114,670 118,685 120,961 121,271 121,846 0.5 33042 Kamloops C' 83,129 84,383 86,200 87,124 87,085 87,654 0.7 37014 Vernon C' 36,922 37,554 38,348 39,016 38,883 38,990 0.3 7041 Penticton c 32,544 32,857 32,980 33,291 33,068 33,098 0.1 35029 West Kelowna DM" na na 27,169 27,267 27,235 27,408 0.6 39032 Salmon Arm c 16,305 16,652 17,046 17,242 17,123 17,246 0.7 35016 Lake Country DM 9,790 10,221 11,009 11,423 11,509 11,799 2.5 7035 Summerland DM 10,911 11,013 11,143 11,257 11,004 10,942 -0.6 37010 Goldstream DM 9,674 9,904 10,155 10,402 10,286 10,319 0.3 39019 Revelstoke C' 7,288 7,273 7,268 7,276 7,269 7,329 0.8 33006 Merritt c 7,338 7,393 7,455 7,460 7,283 7,230 -0.7 7005 Osoyoos T 4,790 4,928 5,045 5,196 5,201 5,210 0.2 35018 Peachland DM 4,938 5,113 5,222 5,250 5,170 5,160 -0.2 37024 Spallumcheen DM 4,991 4,983 5,017 5,135 5,152 5,155 0.1 7014 Oliver T' 4,374 4,450 4,594 4,788 4,549 4,478 -1.6 37028 Armstrong c 4,342 4,350 4,468 4,539 4,513 4,413 -2.2 39007 Golden T 3,876 3,858 3,914 3,964 3,934 3,934 0.0 7024 Princeton T 2,685 2,696 2,722 2,761 2,994 3,073 2.6 37033 Enderby c 2,845 2,869 2,890 2,910 2,923 2,936 0.4 39045 Sicamous DM 2,684 2,750 2,939 2,953 2,962 2,913 -1.7 33054 Chase VL 2,439 2,409 2,469 2,481 2,487 2,497 0.4 33067 ClearWater oM" na na 2,382 2,364 2,355 2,314 -1.7 33035 Logan Lake DM 2,198 2,194 2,198 2,193 2,207 2,215 0.4 37005 Lumby VL' 1,658 1,710 1,754 1,806 1,815 1,863 2.6 33019 Ashcroft VL 1,671 1,722 1,741 1,742 1,755 1,756 0.1 33074 Bariere DM~ na na 1,725 1,723 1,712 1,693 -1.1 7009 Keremeos VL 1,289 1,325 1,462 1,514 1,516 1,531 1.0 33024 Cache Creek VL 1,045 1,058 1,085 1,085 1,084 1,087 0.3 33028 Clinton VL 578 573 597 598 603 609 1.0 33045 Sun Peaks Mountain VL" na na na na 396 405 2.3 33015 Lytton VL 235 231 226 226 226 224 -0.9 Unincorporated Areas RDR 132,128 134,991 108,030 111,068 110,934 111,703 0.7 Kootenay 143,411 146,055 149,806 152,018 152,490 152,833 0.2 1022 Cranbrook C' 18,493 18,585 18,938 19,185 19,117 18,932 -1.0 3015 Nelson C' 9,327 9,475 9,803 9,951 9,791 9,804 0.1 3045 Castlegar c 7,360 7,510 7,631 7,881 7,877 7,911 0.4 5014 Trail c 7,248 7,366 7,365 7,362 7,240 7,260 0.3 1028 Kimberley c 6,184 6,323 6,523 6,713 6,646 6,683 0.6 3004 Creston T 4,837 4,988 5,193 5,252 5,244 5,224 -0.4 1012 Fernie C' 4,289 4,293 4,367 4,420 4,409 4,458 1.1 5032 Grand Forks c 4,059 4,104 4,184 4,155 3,997 3,917 -2.0 1006 Sparwood DM 3,680 3,704 3,780 3,809 3,770 3,778 0.2 1039 lnvermere DM 3,046 3,184 3,465 3,672 3,617 3,653 1.0 5023 Rossland c 3,278 3,333 3,476 3,536 3,553 3,563 0.3 1003 Elkford DM 2,517 2,518 2,559 2,606 2,705 2,730 0.9 5005 Fruitvale VL 1,968 2,010 2,049 2,034 2,012 2,022 0.5 5018 Warfield VL 1,739 1,794 1,799 1,813 1,808 1,801 -0.4 3050 Nakusp VL 1,524 1,512 1,523 1,532 1,536 1,532 -0.3 3023 Kaslo VL 1,073 1,167 1,170 1,186 1,183 1,184 0.1 3011 Salmo VL 1,008 1,027 1,048 1,061 1,070 1,073 0.3 5009 Montrose VL 1,018 1,023 1,046 1,044 1,046 1,047 0.1 1040 Radium Hot Springs VL 738 892 973 1,006 1,015 1,028 1.3 1043 Canal Flats VL 701 747 783 818 826 813 -1.6 5042 Greenwood c 625 633 668 677 685 692 1.0 5037 Midway VL 621 643 662 658 663 669 0.9 3032 New Denver VL 512 503 526 517 510 515 1.0 3019 Slocan VL 314 345 369 391 397 399 0.5 3027 Silverton VL 186 192 198 202 205 203 -1.0 Unincorporated Areas RDR 57,066 58,184 59,708 60,537 61,568 61,942 0.6 Cariboo 157,633 158,360 159,987 160,894 161,998 162,775 0.5 53023 Prince George c 72,890 73,346 73,899 74,639 75,546 75,828 0.4 41009 Williams Lake C' 11,082 11,107 11,144 11,103 10,998 11,006 0.1 41013 Quesnel c' 9,475 9,504 9,627 9,722 9,743 9,947 2.1 53033 Mackenzie DM 4,616 4,534 4,255 3,831 3,705 3,738 0.9 41005 100 Mile House DM 1,912 1,919 1,933 1,943 1,954 1,974 1.0 53007 Valemount VL 1,018 1,007 1,015 1,045 1,062 1,070 0.8 53012 McBride VL 661 659 678 675 677 697 3.0 41025 Wells DM 236 244 257 257 278 304 9.4 Unincorporated Areas RDR 55,743 56,040 57,179 57,679 58,035 58,211 0.3 Appendix 3 to SEMI/SEPP 1.30 Revised January 10, 2013 North Coast 58,784 58,079 58,756 58,938 59,124 59,184 0.1 47012 Prince Rupert c 13,072 12,907 12,832 12,862 12,990 12,935 -0.4 49011 Terrace c 11,475 11,358 11,553 11,689 11,927 12,044 1.0 49005 Kitimat OM 9,328 9,096 9,182 9,238 9,176 9,098 -0.9 47026 Village of Queen Charlott VL 950 951 952 962 959 952 -0.7 47023 Masset VL 947 937 913 930 920 924 0.4 49024 New Hazelton OM 627 610 611 605 603 617 2.3 47007 Port Edward OM 581 577 585 571 571 566 -0.9 49032 Stewart OM 496 481 510 491 495 499 0.8 47030 Port Clements VL 443 450 461 454 456 457 0.2 49022 Hazelton VL 293 296 298 305 302 314 4.0 Unincorporated Areas RDR 20,572 20,416 20,859 20,831 20,725 20,778 0.3 Nechako 39,996 39,626 39,463 39,552 39,785 39,952 0.4 51043 Smithers T 5,292 5,207 5,288 5,328 5,407 5,347 -1.1 51007 Vanderhoof OM 4,172 4,144 4,123 4,148 4,047 4,114 1.7 51034 Houston DM 3,197 3,062 3,007 2,962 3,007 3,039 1.1 51022 Burns Lake VL 2,154 2,164 2,149 2,117 2,142 2,116 ·1.2 51038 Telkwa VL 1,333 1,332 1,359 1,359 1,402 1,441 2.8 51013 Fort St. James OM 1,362 1,362 1,343 1,323 1,295 1,339 3.4 51009 Fraser Lake VL 1,129 1,135 1,119 1,123 1,160 1,172 1.0 51032 Gran isle VL 365 377 390 396 396 389 ·1.8 20,992 20,843 20,685 20,796 20,929 20,995 0.3 Northeast 65,628 66,345 67,067 68,300 69,558 70,604 1.5 55034 Fort St. John c 17,933 18,394 18,796 19,481 19,867 20,408 2.7 55014 Dawson Creek c' 11,094 11,290 11,422 11,528 11,856 12,257 3.4 Northern Rockies Regional 59007 Municipality RG~ na na na 5,565 5,742 5,855 2.0 55010 Chetwynd DM 2,722 2,638 2,640 2,680 2,713 2,706 -0.3 55003 Tumbler Ridge DM 2,491 2,434 2,441 2,421 2,428 2,436 0.3 55030 Taylor DM 1,386 1,403 1,469 1,483 1,497 1,501 0.3 55025 Hudson's Hope DM 1,012 1,009 1,031 1,052 1,056 1,055 -0.1 55005 Pouce Coupe VL' 738 744 738 747 792 804 1.5 59005 Fort Nelson T' 4,612 4,457 4,399 na na na na 55999 Unincorporated Areas RDR 23,640 23,976 24,131 23,343 23,607 23,582 -0.1 British Columbia 4,243,580 4,309,632 4,384,047 4,459,947 4,529,674 4,573,321 1.0 Source: Demographic Analysis Section, BC Slats Ministry of Citizens' Services Government of British Columbia Dec, 2011 Notes: RD =Regional District, R = Region, RDR =Regional District Unincorporated Area, RM =Resort Municipality, /GO =Indian Government District, C =City, T =Town, VL =Village, OM =District Municipality, IM = Is/and Municipality, RGM = Regional Municipality. All figures correspond to municipal boundaries as of July 1st of the year stated. All figures are as of July 1st of the year stated. SGC =Standard Geographical Classification ' Denotes a boundary or status change between July 1, 2006 and June 30, 2011. < New incorporations: Clearwater on Dec 3, 2007; Barriere on Dec 4, 2007; West Kelowna (formerly Westside) on Dec 6, 2007; Northern Rockies Regional Municipality on Feb 6, 2009; Sun Peaks Resort Municipality on Jun 28, 2010. Appendix 3 to SEMI/SEPP 1.30 Revised January 10, 2013 o The Sechelt Indian Government District is split between two Regional Districts, thus the two table occurrences here. • Comox Strathcona RD split into Comox RD and Strathcona RD Feb 15, 2008. " Dease Lake area incorporated into Kitimat-Stikine RD (from Stikine) on June 21, 2007. Appendix 3 to SEMI/SEPP 1.30 Revised Januarv 10. 2013 British Columbia Municipal Population Estimates - Sorted by Names Area 2010-2011 SGC Name Type 2006 2007 2008 2009 2010 2011 %Change 41005 100 Mile House OM 1,912 1,919 1,933 1,943 1,954 1,974 1.0 9052 Abbotsford c, 129,345 131,250 133,547 136,031 138,139 139,343 0.9 43008 Alert Bay VL 477 476 487 479 485 485 0.0 15038 An more VL 1,887 2,030 2,122 2,162 2,202 2,265 2.9 37028 Armstrong c 4,342 4,350 4,468 4,539 4,513 4,413 -2.2 33019 Ashcroft VL 1,671 1,722 1,741 1,742 1,755 1,756 0.1 33074 Bariere DM 2 na na 1,725 1,723 1,712 1,693 -1.1 15036 Belcarra VL 688 679 688 682 690 689 -0.1 15062 Bowen Island IM 3,468 3,522 3,582 3,613 3,677 3,716 1.1 15025 Burnaby c 210,507 214,938 218,440 223,076 227,323 229,464 0.9 51022 Burns Lake VL 2,154 2,164 2,149 2,117 2,142 2,116 -1.2 33024 Cache Creek VL 1,045 1,058 1,085 1,085 1,084 1,087 0.3 24034 Campbell River c, 30,054 30,447 31,006 31,367 31,571 31,771 0.6 1043 Canal Flats VL 701 747 783 818 826 813 -1.6 3045 Castlegar c 7,360 7,510 7,631 7,881 7,877 7,911 0.4 17015 Central Saanich DM 16,006 16,024 16,171 16,190 16,197 16,183 -0.1 33054 Chase VL 2,439 2,409 2,469 2,481 2,487 2,497 0.4 55010 Chetwynd OM 2,722 2,638 2,640 2,680 2,713 2,706 -0.3 9020 Chilliwack c 71,298 73,300 74,943 76,200 77,953 78,898 1.2 33067 Clear Water DM2 na na 2,382 2,364 2,355 2,314 -1.7 33028 Clinton VL 578 573 597 598 603 609 1.0 37010 Goldstream DM 9,674 9,904 10,155 10,402 10,286 10,319 0.3 17041 Colwood c 15,260 15,582 15,948 16,194 16,574 16,721 0.9 26005 Com ox T, 12,401 12,721 13,265 13,460 13,640 13,493 -1.1 15034 Coquitlam c 119,582 120,260 121,574 123,362 126,558 127,785 1.0 26010 Courtenay c, 22,481 23,369 23,981 24,246 24,582 24,967 1.6 1022 Cranbrook c, 18,493 18,585 18,938 19,185 19,117 18,932 -1.0 3004 Creston T 4,837 4,988 5,193 5,252 5,244 5,224 -0.4 26014 Cumberland VL 2,765 2,880 3,045 3,167 3,252 3,311 1.8 55014 Dawson Creek c, 11,094 11,290 11,422 11,528 11,856 12,257 3.4 15011 Delta DM 99,490 99,302 99,523 99,984 99,971 100,094 0.1 19012 Duncan c 5,035 4,978 4,995 5,014 4,985 4,900 -1.7 1003 Elkford OM 2,517 2,518 2,559 2,606 2,705 2,730 0.9 37033 Enderby c 2,845 2,869 2,890 2,910 2,923 2,936 0.4 17040 Esquimalt OM 17,513 17,528 17,661 17,704 17,684 17,654 -0.2 1012 Fernie c, 4,289 4,293 4,367 4,420 4,409 4,458 1.1 59005 Fort Nelson T, 4,612 4,457 4,399 na na na na Appendix 3 to SEMI/SEPP 1.30 Revised Januarv 10, 2013 51013 Fort St. James DM 1,362 1,362 1,343 1,323 1,295 1,339 3.4 55034 Fort St. John c 17,933 18,394 18,796 19,481 19,867 20,408 2.7 51009 Fraser Lake VL 1,129 1,135 1 '119 1,123 1,160 1,172 1.0 5005 Fruitvale VL 1,968 2,010 2,049 2,034 2,012 2,022 0.5 29005 Gibsons T 4,212 4,336 4,361 4,453 4,414 4,450 0.8 24025 Gold River VL 1,371 1,411 1,425 1,426 1,410 1,386 -1.7 39007 Golden T 3,876 3,858 3,914 3,964 3,934 3,934 0.0 5032 Grand Forks c 4,059 4,104 4,184 4,155 3,997 3,917 -2.0 51032 Granisle VL 365 377 390 396 396 389 -1.8 5042 Greenwood c 625 633 668 677 685 692 1.0 9027 Harrison Hot Springs VL 1,578 1,584 1,597 1,596 1,597 1,597 0.0 49022 Hazelton VL 293 296 298 305 302 314 4.0 17049 Highlands DM 2,010 2,036 2,115 2,178 2,256 2,293 1.6 9009 Hope DM 6,243 6,161 6,203 6,277 6,320 6,201 -1.9 51034 Houston DM 3,197 3,062 3,007 2,962 3,007 3,039 1.1 55025 Hudson's Hope DM 1,012 1,009 1,031 1,052 1,056 1,055 -0.1 1039 lnvermere DM 3,046 3,184 3,465 3,672 3,617 3,653 1.0 33042 Kamloops c1 83,129 84,383 86,200 87,124 87,085 87,654 0.7 3023 Kaslo VL 1,073 1,167 1,170 1,186 1,183 1,184 0.1 35010 Kelowna c1 110,351 114,670 118,685 120,961 121,271 121,846 0.5 9032 Kent DM 5,318 5,341 5,461 5,522 5,578 5,535 -0.8 7009 Keremeos VL 1,289 1,325 1,462 1,514 1,516 1,531 1.0 1028 Kimberley c 6,184 6,323 6,523 6,713 6,646 6,683 0.6 49005 Kitimat DM 9,328 9,096 9,182 9,238 9,176 9,098 -0.9 19021 Ladysmith T1 7,637 7,899 8,066 8,128 8,240 8,328 1.1 35016 Lake Country DM 9,790 10,221 11,009 11,423 11,509 11,799 2.5 19016 Lake Cowichan T1 2,973 2,962 3,025 3,186 3,183 3,140 -1.4 17044 Langford c 23,513 24,766 26,123 27,362 29,150 30,263 3.8 15001 Langley District Municipality DM 96,792 99,020 101,435 103,394 104,666 105,747 1.0 15002 Langley, City of c 24,899 25,169 25,388 25,557 25,850 26,119 1.0 21008 Lanzville DM 3,685 3,721 3,745 3,701 3,688 3,641 -1.3 31026 Lillooet DM 2,355 2,318 2,373 2,370 2,367 2,367 0.0 15065 Lions Bay VL 1,406 1,403 1,398 1,400 1,394 1,408 1.0 33035 Logan Lake DM 2,198 2,194 2,198 2,193 2,207 2,215 0.4 1 37005 Lumby VL 1,658 1,710 1,754 1,806 1,815 1,863 2.6 33015 Lytton VL 235 231 226 226 226 224 -0.9 53033 Mackenzie DM 4,616 4,534 4,255 3,831 3,705 3,738 0.9 15075 Maple Ridge DM 71,453 72,508 73,988 75,143 76,396 77,402 1.3 47023 Masset VL 947 937 913 930 920 924 0.4 53012 McBride VL 661 659 678 675 677 697 3.0 33006 Merritt c 7,338 7,393 7,455 7,460 7,283 7,230 -0.7 17042 Metchosin DM 4,969 5,061 5,108 5,139 5,306 5,326 0.4 Appendix 3 to SEMI/SEPP 1.30 Revised Januarv 10. 2013 5037 Midway VL 621 643 662 658 663 669 0.9 9056 Mission DM 35,741 36,283 36,758 37,213 37,563 37,372 -0.5 5009 Montrose VL 1,018 1,023 1,046 1,044 1,046 1,047 0.1 3050 Nakusp VL 1,524 1,512 1,523 1,532 1,536 1,532 -0.3 21007 Nanaimo c 80,757 81,464 82,763 84,331 85,487 86,961 1.7 3015 Nelson c1 9,327 9,475 9,803 9,951 9,791 9,804 0.1 3032 New Denver VL 512 503 526 517 510 515 1.0 49024 New Hazelton DM 627 610 611 605 603 617 2.3 15029 New Westminster c 60,533 61,783 63,783. 65,096 66,873 67,880 1.5 19008 North Cowichan DM 28,408 28,801 29,249 29,530 29,828 30,125 1.0 17005 North Saanich DM 10,923 10,875 11,045 11,034 11,108 11 '128 0.2 15046 North Vancouver District Municipality DM 85,472 85,974 86,114 86,832 88,345 88,678 0.4 15051 North Vancouver, City of c 46,910 47,282 47,783 48,941 50,711 51,083 0.7 2 59007 Northern Rockies Regional Municipality RGM na na na 5,565 5,742 5,855 2.0 17030 Oak Bay DM 18,040 17,971 18,070 18,035 18,006 18,024 0.1 7014 Oliver T1 4,374 4,450 4,594 4,788 4,549 4,478 -1.6 7005 Osoyoos T 4,790 4,928 5,045 5,196 5,201 5,210 0.2 21018 Parksville c 11,090 11,315 11,617 11,798 11,828 11,584 -2.1 35018 Peachland DM 4,938 5,113 5,222 5,250 5,170 5,160 -0.2 31012 Pemberton VL 2,349 2,359 2,339 2,419 2,437 2,399 -1.6 7041 Penticton c 32,544 32,857 32,980 33,291 33,068 33,098 0.1 15070 Pitt Meadows c1 16,297 16,584 17,434 17,937 18,131 18,355 1.2 23008 Port Alberni c1 17,615 17,624 17,681 17,763 17,747 17,836 0.5 43017 Port Alice VL 828 841 843 843 842 837 -0.6 47030 Port Clements VL 443 450 461 454 456 457 0.2 15039 Port Coquitlam c 54,538 54,976 55,574 56,516 57,414 57,646 0.4 47007 Port Edward DM 581 577 585 571 571 566 -0.9 43023 Port Hardy DM 3,976 3,925 3,933 3,991 3,949 3,917 -0.8 43012 Port McNeill T 2,681 2,655 2,605 2,622 2,647 2,633 -0.5 15043 Port Moody c 28,747 29,947 31,511 33,039 33,923 34,488 1.7 55005 Pouce Coupe VL1 738 744 738 747 792 804 1.5 27008 Powell River c 13,027 13,145 13,285 13,355 13,570 13,597 0.2 53023 Prince George c 72,890 73,346 73,899 74,639 75,546 75,828 0.4 47012 Prince Rupert c 13,072 12,907 12,832 12,862 12,990 12,935 -0.4 7024 Princeton T 2,685 2,696 2,722 2,761 2,994 3,073 2.6 21023 Qualicum Beach T 8,516 8,619 8,754 8,776 8,727 8,646 -0.9 41013 Quesnel c1 9,475 9,504 9,627 9,722 9,743 9,947 2.1 1040 Radium Hot Springs VL 738 892 973 1,006 1,015 1,028 1.3 39019 Revel stoke c1 7,288 7,273 7,268 7,276 7,269 7,329 0.8 15015 Richmond c 182,652 186,395 189,064 193,491 196,801 197,631 0.4 5023 Ross land c 3,278 3,333 3,476 3,536 3,553 3,563 0.3 17021 Saanich DM 111,575 112,072 113,203 113,656 114,107 113,999 -0.1 Appendix 3 to SEMI/SEPP 1.30 Revised Januarv 10, 2013 3011 Salmo VL 1,008 1,027 1,048 1,061 1,070 1,073 0.3 39032 Salmon Arm c 16,305 16,652 17,046 17,242 17,123 17,246 0.7 24039 Sayward VL 341 326 329 332 334 339 1.5 29011 Sechelt OM 8,501 8,767 9,017 9,176 9,494 9,727 2.5 3 27806 Sechelt lnd Gov Dist (Part) IGD 17 17 18 18 18 18 0.0 3 29803 Sechelt lnd Gov Dist (Part) IGD 827 814 815 832 827 807 -2.4 39045 Sicamous DM 2,684 2,750 2,939 2,953 2,962 2,913 -1.7 17010 Sidney T 11,510 11,552 11,551 11,592 11,597 11,583 -0.1 3027 Silverton VL 186 192 198 202 205 203 -1.0 3019 Slocan VL 314 345 369 391 397 399 0.5 51043 Smithers T 5,292 5,207 5,288 5,328 5,407 5,347 -1.1 17052 Sooke DM 10,077 10,334 10,414 10,553 10,873 10,919 0.4 37024 Spallumcheen DM 4,991 4,983 5,017 5,135 5,152 5,155 0.1 1006 Sparwood DM 3,680 3,704 3,780 3,809 3,770 3,778 0.2 31006 Squamish DM 15,495 15,982 16,586 17,202 17,892 18,712 4.6 49032 Stewart DM 496 481 510 491 495 499 0.8 7035 Summerland DM 10,911 11,013 11 '143 11,257 11,004 10,942 -0.6 2 33045 Sun Peaks Mountain VL na na na na 396 405 2.3 15004 Surrey c 412,734 422,915 434,583 447,106 462,211 473,238 2.4 24030 Tahsis VL 366 354 380 381 380 372 -2.1 55030 Taylor DM 1,386 1,403 1,469 1,483 1,497 1,501 0.3 51038 Telkwa VL 1,333 1,332 1,359 1,359 1,402 1,441 2.8 49011 Terrace c 11,475 11,358 11,553 11,689 11,927 12,044 1.0 23025 Totino DM 1,750 1,773 1,812 1,831 1,894 1,922 1.5 5014 Trail c 7,248 7,366 7,365 7,362 7,240 7,260 0.3 55003 Tumbler Ridge DM 2,491 2,434 2,441 2,421 2,428 2,436 0.3 23019 Ucluelet DM 1,522 1,545 1,577 1,593 1,605 1,634 1.8 53007 Valemount VL 1,018 1,007 1,015 1,045 1,062 1,070 0.8 15022 Vancouver c 599,765 609,974 615,888 628,600 642,657 651,048 1.3 51007 Vanderhoof OM 4,172 4,144 4,123 4,148 4,047 4,114 1.7 37014 Vernon c1 36,922 37,554 38,348 39,016 38,883 38,990 0.3 17034 Victoria c 80,871 81,657 81,890 82,886 83,338 84,031 0.8 17047 View Royal T 9,126 9,171 9,355 9,595 9,740 9,838 1.0 47026 Village of Queen Charlott VL 950 951 952 962 959 952 -0.7 5018 Warfield VL 1,739 1,794 1,799 1,813 1,808 1,801 -0.4 41025 Wells DM 236 244 257 257 278 304 9.4 35029 West Kelowna DM2 na na 27,169 27,267 27,235 27,408 0.6 15055 West Vancouver OM 42,863 42,977 42,915 43,361 44,046 44,096 0.1 31020 Whistler RM1 9,796 9,750 9,688 10,241 10,528 10,437 -0.9 15007 White Rock c 18,916 18,998 18,901 19,126 19,272 19,313 0.2 41009 Williams Lake c1 11,082 11,107 11,144 11,103 10,998 11,006 0.1 24029 Zeballos VL 189 182 174 162 166 171 3.0 Appendix 3 to SEMI/SEPP 1.30 Revised January 10. 2013 Total Municipalities 3,722,341 3,781,105 3,874,515 3,944,031 4,007,875 4,047,133 1.0 Other BC Areas 521,239 528,527 509,532 515,916 521,799 526,188 1.0 BC Total Population 4,243,580 4,309,632 4,384,047 4,459,947 4,529,674 4,573,321 1.0 Source: Demographic Analysis Section, BC Stats Ministry of Citizens' Services Government of British Columbia Dec/2011 Notes: C =City, T = Town, VL = Village, DM =District Municipality, IM =Island Municipality, RGM =Regional Municipality. RM = Resort Municipality, IGD = Indian Government District, All figures correspond to municipal boundaries as of July 1st of the year stated. All figures are as of July 1st of the year stated. SGC =Standard Geographical Classification 1 Denotes a boundary or status change between July 1, 2006 and June 30, 2011. 2 New incorporations: Clearwater on Dec 3, 2007; Barriere on Dec 4, 2007; West Kelowna (formerly Westside) on Dec 6, 2007; Northern Rockies Regional Municipality on Feb 6, 2009; Sun Peaks Resort Municipality on Jun 28, 2010. 3 The Sechelt Indian Government District is split between two Regional Districts, thus the two table occurrences here. 4 Comox Strathcona RD split into Comox RD and Strathcona RD Feb 15, 2008. 5 Dease Lake area incorporated into Kitimat-Stikine RD (from Stikine) on June 21, 2007. Appendix 3 to SEMI/SEPP 1.30 Revised Januarv 10. 2013 British Columbia Municipal Population Estimates -Sorted by Size (2011) Area 2010-2011 SGC Name T~pe 2006 2007 2008 2009 2010 2011 %Chanae 15022 Vancouver c 599,765 609,974 615,888 628,600 642,657 651,048 1.3 15004 Surrey c 412,734 422,915 434,583 447,106 462,211 473,238 2.4 15025 Burnaby c 210,507 214,938 218,440 223,076 227,323 229,464 0.9 15015 Richmond c 182,652 186,395 189,064 193,491 196,801 197,631 0.4 9052 Abbotsford c1 129,345 131,250 133,547 136,031 138,139 139,343 0.9 15034 Coquitlam c 119,582 120,260 121,574 123,362 126,558 127,785 1.0 35010 Kelowna c1 110,351 114,670 118,685 120,961 121,271 121,846 0.5 17021 Saanich OM 111,575 112,072 113,203 113,656 114,107 113,999 -0.1 15001 Langley District Municipality OM 96,792 99,020 101,435 103,394 104,666 105,747 1.0 15011 Delta OM 99,490 99,302 99,523 99,984 99,971 100,094 0.1 15046 North Vancouver District Municipality OM 85,472 85,974 86,114 86,832 88,345 88,678 0.4 33042 Kamloops c1 83,129 84,383 86,200 87,124 87,085 87,654 0.7 21007 Nanaimo c 80,757 81,464 82,763 84,331 85,487 86,961 1.7 17034 Victoria c 80,871 81,657 81,890 82,886 83,338 84,031 0.8 9020 Chilliwack c 71,298 73,300 74,943 76,200 77,953 78,898 1.2 15075 Maple Ridge OM 71,453 72,508 73,988 75,143 76,396 77,402 1.3 53023 Prince George c 72,890 73,346 73,899 74,639 75,546 75,828 0.4 15029 New Westminster c 60,533 61,783 63,783 65,096 66,873 67,880 1.5 15039 Port Coquitlam c 54,538 54,976 55,574 56,516 57,414 57,646 0.4 15051 North Vancouver, City of c 46,910 47,282 47,783 48,941 50,711 51,083 0.7 15055 West Vancouver OM 42,863 42,977 42,915 43,361 44,046 44,096 0.1 37014 Vernon c1 36,922 37,554 38,348 39,016 38,883 38,990 0.3 9056 Mission OM 35,741 36,283 36,758 37,213 37,563 37,372 -0.5 15043 Port Moody c 28,747 29,947 31,511 33,039 33,923 34,488 1.7 7041 Penticton c 32,544 32,857 32,980 33,291 33,068 33,098 0.1 24034 Campbell River c1 30,054 30,447 31,006 31,367 31,571 31,771 0.6 17044 Langford c 23,513 24,766 26,123 27,362 29,150 30,263 3.8 19008 North Cowichan OM 28,408 28,801 29,249 29,530 29,828 30,125 1.0 35029 West Kelowna DM 2 na na 27,169 27,267 27,235 27,408 0.6 15002 Langley, City of c 24,899 25,169 25,388 25,557 25,850 26,119 1.0 26010 Courtenay c1 22,481 23,369 23,981 24,246 24,582 24,967 1.6 55034 Fort St. John c 17,933 18,394 18,796 19,481 19,867 20,408 2.7 15007 White Rock c 18,916 18,998 18,901 19,126 19,272 19,313 0.2 1022 Cranbrook c1 18,493 18,585 18,938 19,185 19,117 18,932 -1.0 31006 Squamish OM 15,495 15,982 16,586 17,202 17,892 18,712 4.6 15070 Pitt Meadows c1 16,297 16,584 17,434 17,937 18,131 18,355 1.2 Appendix 3 to SEMI/SEPP 1.30 Revised Januarv 10. 2013 17030 Oak Bay OM 18,040 17,971 18,070 18,035 18,006 18,024 0.1 23008 Port Alberni c1 17,615 17,624 17,681 17,763 17,747 17,836 0.5 17040 Esquimalt OM 17,513 17,528 17,661 17,704 17,684 17,654 -0.2 39032 Salmon Arm c 16,305 16,652 17,046 17,242 17,123 17,246 0.7 17041 Colwood c 15,260 15,582 15,948 16,194 16,574 16,721 0.9 17015 Central Saanich OM 16,006 16,024 16,171 16,190 16,197 16,183 -0.1 27008 Powell River c 13,027 13,145 13,285 13,355 13,570 13,597 0.2 26005 Comox T1 12.401 12,721 13,265 13.460 13,640 13.493 -1.1 47012 Prince Rupert c 13,072 12,907 12,832 12,862 12,990 12,935 -0.4 55014 Dawson Creek c1 11,094 11,290 11,422 11,528 11,856 12,257 3.4 49011 Terrace c 11.475 11,358 11,553 11,689 11,927 12,044 1.0 35016 Lake Country OM 9,790 10,221 11,009 11.423 11,509 11,799 2.5 21018 Parksville c 11,090 11,315 11,617 11,798 11,828 11,584 -2.1 17010 Sidney T 11,510 11,552 11,551 11,592 11,597 11,583 -0.1 17005 North Saanich OM 10,923 10,875 11,045 11,034 11,108 11,128 0.2 41009 Williams Lake c1 11,082 11,107 11,144 11,103 10,998 11,006 0.1 7035 Summerland OM 10,911 11,013 11,143 11,257 11,004 10,942 -0.6 17052 Sooke OM 10,077 10,334 10.414 10,553 10,873 10,919 0.4 1 31020 Whistler RM 9,796 9,750 9,688 10,241 10,528 10.437 -0.9 37010 Goldstream OM 9,674 9,904 10,155 10.402 10,286 10,319 0.3 41013 Quesnel c1 9.475 9,504 9,627 9,722 9,743 9,947 2.1 17047 View Royal T 9,126 9,171 9,355 9,595 9,740 9,838 1.0 3015 Nelson c1 9,327 9,475 9,803 9,951 9,791 9,804 0.1 29011 Sechelt OM 8,501 8,767 9,017 9,176 9,494 9,727 2.5 49005 Kitimat OM 9,328 9,096 9,182 9,238 9,176 9,098 -0.9 21023 Qualicum Beach T 8,516 8,619 8,754 8,776 8,727 8,646 -0.9 19021 Ladysmith T1 7,637 7,899 8,066 8,128 8,240 8,328 1.1 3045 Castlegar c 7,360 7,510 7,631 7,881 7,877 7,911 0.4 39019 Revelstoke c1 7,288 7,273 7,268 7,276 7,269 7,329 0.8 5014 Trail c 7,248 7,366 7,365 7,362 7,240 7,260 0.3 33006 Merritt c 7,338 7,393 7,455 7.460 7,283 7,230 -0.7 1028 Kimberley c 6,184 6,323 6,523 6,713 6,646 6,683 0.6 9009 Hope OM 6,243 6,161 6,203 6,277 6,320 6,201 -1.9 2 59007 Northern Rockies Regional Municipality RGM na na na 5,565 5,742 5,855 2.0 9032 Kent OM 5,318 5,341 5.461 5,522 5,578 5,535 -0.8 51043 Smithers T 5,292 5,207 5,288 5,328 5,407 5,347 -1.1 17042 Metchosin OM 4,969 5,061 5,108 5,139 5,306 5,326 0.4 3004 Creston T 4,837 4,988 5,193 5,252 5,244 5,224 -0.4 7005 Osoyoos T 4,790 4,928 5,045 5,196 5,201 5,210 0.2 35018 Peachland OM 4,938 5,113 5,222 5,250 5,170 5,160 -0.2 37024 Spallumcheen OM 4,991 4,983 5,017 5,135 5,152 5,155 0.1 19012 Duncan c 5,035 4,978 4,995 5,014 4,985 4,900 -1.7 Appendix 3 to SEMI/SEPP 1.30 Revised January 10. 2013 7014 Oliver T1 4,374 4,450 4,594 4,788 4,549 4,478 -1.6 1012 Fernie c1 4,289 4,293 4,367 4,420 4,409 4,458 1.1 29005 Gibsons T 4,212 4,336 4,361 4,453 4,414 4,450 0.8 37028 Armstrong c 4,342 4,350 4,468 4,539 4,513 4,413 -2.2 51007 Vanderhoof OM 4,172 4,144 4,123 4,148 4,047 4,114 1.7 39007 Golden T 3,876 3,858 3,914 3,964 3,934 3,934 0.0 5032 Grand Forks c 4,059 4,104 4,184 4,155 3,997 3,917 -2.0 43023 Port Hardy OM 3,976 3,925 3,933 3,991 3,949 3,917 -0.8 1006 Sparwood OM 3,680 3,704 3,780 3,809 3,770 3,778 0.2 53033 Mackenzie OM 4,616 4,534 4,255 3,831 3,705 3,738 0.9 15062 Bowen Island IM 3,468 3,522 3,582 3,613 3,677 3,716 1.1 1039 lnvermere OM 3,046 3,184 3,465 3,672 3,617 3,653 1.0 21008 Lanzville OM 3,685 3,721 3,745 3,701 3,688 3,641 -1.3 5023 Rossland c 3,278 3,333 3,476 3,536 3,553 3,563 0.3 26014 Cumberland VL 2,765 2,880 3,045 3,167 3,252 3,311 1.8 19016 Lake Cowichan T1 2,973 2,962 3,025 3,186 3,183 3,140 -1.4 7024 Princeton T 2,685 2,696 2,722 2,761 2,994 3,073 2.6 51034 Houston OM 3,197 3,062 3,007 2,962 3,007 3,039 1.1 37033 Enderby c 2,845 2,869 2,890 2,910 2,923 2,936 0.4 39045 Sicamous OM 2,684 2,750 2,939 2,953 2,962 2,913 -1.7 1003 Elkford OM 2,517 2,518 2,559 2,606 2,705 2,730 0.9 55010 Chetwynd OM 2,722 2,638 2,640 2,680 2,713 2,706 -0.3 43012 Port McNeill T 2,681 2,655 2,605 2,622 2,647 2,633 -0.5 33054 Chase VL 2,439 2,409 2,469 2,481 2,487 2,497 0.4 55003 Tumbler Ridge OM 2,491 2,434 2,441 2,421 2,428 2,436 0.3 31012 Pemberton VL 2,349 2,359 2,339 2,419 2,437 2,399 -1.6 31026 Lillooet OM 2,355 2,318 2,373 2,370 2,367 2,367 0.0 33067 ClearWater OM2 na na 2,382 2,364 2,355 2,314 -1.7 17049 Highlands OM 2,010 2,036 2,115 2,178 2,256 2,293 1.6 15038 Anmore VL 1,887 2,030 2,122 2,162 2,202 2,265 2.9 33035 Logan Lake OM 2,198 2,194 2,198 2,193 2,207 2,215 0.4 51022 Burns Lake VL 2,154 2,164 2,149 2,117 2,142 2,116 -1.2 5005 Fruitvale VL 1,968 2,010 2,049 2,034 2,012 2,022 0.5 41005 1 00 Mile House OM 1,912 1,919 1,933 1,943 1,954 1,974 1.0 23025 Totino OM 1,750 1,773 1,812 1,831 1,894 1,922 1.5 1 37005 Lumby VL 1,658 1,710 1,754 1,806 1,815 1,863 2.6 5018 Warfield VL 1,739 1,794 1,799 1,813 1,808 1,801 -0.4 33019 Ashcroft VL 1,671 1,722 1,741 1,742 1,755 1,756 0.1 33074 Bariere OM2 na na 1,725 1,723 1,712 1,693 -1.1 23019 Ucluelet OM 1,522 1,545 1,577 1,593 1,605 1,634 1.8 9027 Harrison Hot Springs VL 1,578 1,584 1,597 1,596 1,597 1,597 0.0 3050 Nakusp VL 1,524 1,512 1,523 1,532 1,536 1,532 -0.3 Appendix 3 to SEMI/SEPP 1.30 Revised Januarv 10, 2013 7009 Keremeos VL 1,289 1,325 1,462 1,514 1,516 1,531 1.0 55030 Taylor OM 1,386 1,403 1,469 1,483 1,497 1,501 0.3 51038 Telkwa VL 1,333 1,332 1,359 1,359 1,402 1,441 2.8 15065 Lions Bay VL 1,406 1,403 1,398 1,400 1,394 1,408 1.0 24025 Gold River VL 1,371 1,411 1,425 1,426 1,410 1,386 -1.7 51013 Fort St. James OM 1,362 1,362 1,343 1,323 1,295 1,339 3.4 3023 Kaslo VL 1,073 1,167 1,170 1,186 1,183 1,184 0.1 51009 Fraser Lake VL 1,129 1,135 1,119 1,123 1,160 1,172 1.0 33024 Cache Creek VL 1,045 1,058 1,085 1,085 1,084 1,087 0.3 3011 Salmo VL 1,008 1,027 1,048 1,061 1,070 1,073 0.3 53007 Valemount VL 1,018 1,007 1,015 1,045 1,062 1,070 0.8 55025 Hudson's Hope OM 1,012 1,009 1,031 1,052 1,056 1,055 -0.1 5009 Montrose VL 1,018 1,023 1,046 1,044 1,046 1,047 0.1 1040 Radium Hot Springs VL 738 892 973 1,006 1,015 1,028 1.3 47026 Village of Queen Charlott VL 950 951 952 962 959 952 -0.7 47023 Masset VL 947 937 913 930 920 924 0.4 43017 Port Alice VL 828 841 843 843 842 837 -0.6 1043 Canal Flats VL 701 747 783 818 826 813 -1.6 29803 Sechelt lnd Gov Dist (Part) IGD3 827 814 815 832 827 807 -2.4 55005 Pouce Coupe VL 1 738 744 738 747 792 804 1.5 53012 McBride VL 661 659 678 675 677 697 3.0 5042 Greenwood c 625 633 668 677 685 692 1.0 15036 Belcarra VL 688 679 688 682 690 689 -0.1 5037 Midway VL 621 643 662 658 663 669 0.9 49024 New Hazelton OM 627 610 611 605 603 617 2.3 33028 Clinton VL 578 573 597 598 603 609 1.0 47007 Port Edward DM 581 577 585 571 571 566 -0.9 3032 New Denver VL 512 503 526 517 510 515 1.0 49032 Stewart DM 496 481 510 491 495 499 0.8 43008 Alert Bay VL 477 476 487 479 485 485 0.0 47030 Port Clements VL 443 450 461 454 456 457 0.2 33045 Sun Peaks Mountain VL2 na na na na 396 405 2.3 3019 Slocan VL 314 345 369 391 397 399 0.5 51032 Gran isle VL 365 377 390 396 396 389 -1.8 24030 Tahsis VL 366 354 380 381 380 372 -2.1 24039 Sayward VL 341 326 329 332 334 339 1.5 49022 Hazelton VL 293 296 298 305 302 314 4.0 41025 Wells OM 236 244 257 257 278 304 9.4 33015 Lytton VL 235 231 226 226 226 224 -0.9 3027 Silverton VL 186 192 198 202 205 203 -1.0 24029 Zeballos VL 189 182 174 162 166 171 3.0 27806 Sechelt lnd Gov Dist (Part) IGD3 17 17 18 18 18 18 0.0 Appendix 3 to SEMI/SEPP 1.30 Revised Januarv 10. 2013 59005 Fort Nelson T1 4,612 4,457 4,399 na na na na Total Municipalities 3,722,341 3,781,105 3,874,515 3,944,031 4,007,875 4,047,133 1.0 Other BC Areas 521,239 528,527 509,532 515,916 521,799 526,188 1.0 BC Total Population 4,243,580 4,309,632 4,384,047 4,459,947 4,529,674 4,573,321 1.0 Source: Demographic Analysis Section, BC Stats Ministry of Citizens' SeNices Government of Bn"tish Columbia Dec/2011 Notes: C =City, T =Town, VL =Village, DM = District Municipality, IM =Island Municipality, RGM =Regional Municipality. RM = Resort Municipality, IGD = Indian Government District, All figures correspond to municipal boundaries as of July 1st of the year stated. All figures are as of July 1st of the year stated. Classification 1 Denotes a boundary or status change between July 1, 2006 and June 30, 2011. 2 New incorporations: Clearwater on Dec 3, 2007; Barriere on Dec 4, 2007; West Kelowna (fonnerly Westside) on Dec 6, 2007; Northern Rockies Regional Municipality on Feb 6, 2009; Sun Peaks Resort Municipality on Jun 28, 2010. 3 The Sechelt Indian Government District is split between two Regional Districts, thus the two table occurrences here. 4 Comox Strathcona RD split into Comox RD and Strathcona RD Feb 15, 2008. 5 Dease Lake area incorporated into Kitimat Stikine RD (from Stikine) on June 21, 2007.