Northern Border Pipeline
Customer Meeting
April 6th & 7th, 2016
Welcome
Bill Fonda
Northern Border Pipeline - Agenda
Welcome
Bill Fonda
8:00 – 8:15 a.m.
System Overview & Projects
Dick Shepherd
8:15 - 8:40
Fundamentals & Capacity Update
Jeff Nielsen
8:40 – 9:05
Maintenance Update
Garrett Word
9:05 – 9:20
Break
9:20 – 9:40
Guest Speaker
Dennis Gartman
Update
Dick Shepherd
9:40 – 10:25
10:25 – 10:35
Forward Looking Information
This presentation may contain certain information that is forward-looking and is subject to important risks and
uncertainties. The words "anticipate", "expect", "believe", "may", "should", "estimate", "project", "outlook",
"forecast" or other similar words are used to identify such forward-looking information. Forward-looking
statements in this presentation are intended to provide TransCanada security holders and potential investors with
information regarding TransCanada and its subsidiaries, including management’s assessment of TransCanada’s
and its subsidiaries’ future financial and operational plans and outlook. Forward-looking statements in this
presentation may include, among others, statements regarding the anticipated business prospects, and financial
performance of TransCanada and its subsidiaries, expectations or projections about the future, strategies and
goals for growth and expansion, expected and future cash flows, costs, schedules (including anticipated
construction and completion dates), operating and financial results, and expected impact of future commitments
and contingent liabilities.
All forward-looking statements reflect TransCanada's beliefs and assumptions based on information available at the
time the statements were made. Actual results or events may differ from those predicted in these forward-looking
statements. Factors that could cause actual results or events to differ materially from current expectations include,
among others, the ability of TransCanada to successfully implement its strategic initiatives and whether such
strategic initiatives will yield the expected benefits, the operating performance of the TransCanada’s pipeline and
energy assets, the availability and price of energy commodities, capacity payments, regulatory processes and
decisions, changes in environmental and other laws and regulations, competitive factors in the pipeline and energy
sectors, construction and completion of capital projects, labour, equipment and material costs, access to capital
markets, interest and currency exchange rates, technological developments and economic conditions in North
America.
By its nature, forward-looking information is subject to various risks and uncertainties, which could cause
TransCanada's actual results and experience to differ materially from the anticipated results or expectations
expressed. Additional information on these and other factors is available in the reports filed by TransCanada with
Canadian securities regulators and with the U.S. Securities and Exchange Commission (SEC). Readers are
cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is
expressed in this presentation or otherwise, and not to use future- oriented information or financial outlooks for
anything other than their intended purpose. TransCanada undertakes no obligation to update publicly or revise any
forward-looking information, whether as a result of new information, future events or otherwise, except as
required by law.
Natural Gas Pipeline Footprint
• Creates one of North America’s
largest regulated natural gas
transmission businesses
• 91,000 km (56,900 miles) of gas
pipeline
• 664 Bcf of storage capacity
• Complements our existing
regulated natural gas pipeline and
storage assets
• Long-term, fee-based contracts
• Diversified customer base
• Adds to basin diversification and
access to large markets
• Established position in the
Appalachia, the fastest growing gas
production basin in North America
• Improves access to U.S. Northeast,
Midwest, Mid-Atlantic and Gulf Coast
markets
Illustrates the configuration of material pipeline systems and
projects within TransCanada’s natural gas pipeline network on
pro forma basis following the completion of the Acquisition
Northern Border & Bison Pipelines
Overview & Projects
Dick Shepherd
Overview & Projects
• Northern Border
• Bison & The Rockies
• The Bakken
• Projects
7
Northern Border Pipeline
AECO
Port of Morgan (POM)
Path
POM - Ventura
Capacity
2.4 Bcfd
Rate
$0.2498
Company
Use Gas*
2.3%
Ventura - Harper
1.5 Bcfd
$0.0478
0.4%
Harp. - Manhattan
1 Bcfd
$0.0801
0.7%
Manhattan - NH
557 MMcfd
$0.0112
0.1%
$0.3889
3.5%
Total
Rates Include: Demand, Commodity, CUS & ACA
*2015 Average Fuel
Ventura
Manhattan
Harper
North Hayden
Northern Border - Growing U.S. Supply
Design Capacity
Name
Port of Morgan
Name
Manning
Kurtz
Total Rockies
WCSB
Pipe
FOOTHILLS
ROCKIES
Pipe
WBI
BISON
Mcf/d
2,192,500
Mcf/d
213,000
407,000
620,000
BAKKEN & WILLISTON
Name
Pipe
Mcf/d
Saskana
OMIMEX
60,000
Stateline
WBI
180,000
Squaw Creek
HILAND PART
95,000
Charbonneau
WBI
60,000
Buford
NNG
48,000
Spring Creek
WBI
446,000
Watford City
HESS
60,000
Little Missouri
TARGA
100,000
Glen Ullin
WBI
100,000
Hay Butte
CALIBER
50,000
Rawson
WBI
405,000
Roosevelt
HILAND PART
50,000
Killdeer
ONEOK
96,000
Total Bakken & Williston
1,750,000
Name
Hebron
Troy Grove
Channahon
Des Plaines
Total Other
OTHER
Pipe
DAKOTA GAS
NICOR
MIDWESTERN
ANR
Mcf/d
160,000
400,000
236,000
60,000
856,000
Northern Border - Major Markets
Design Capacity
Name
Fraser
Balaton
Davis
Lakota
Rutland
Edmunds
Windom
Martin County
Total End User
End User
Pipe
VALERO
MINN CORN
ABE SOUTH
GREEN PLAINS
GREEN PLAINS
NWPUBLICSE
ETHANOL2000
CHS
Mcf/d
21,200
20,000
15,000
15,000
14,000
10,100
10,000
9,600
114,900
Interstate Pipe*
Name
Pipe
Ventura
NNG
Harper
NGPL
Joliet
VECTOR
Jackson Creek
GUARDIAN
Will County
ANR
Welcome
NNG
Channahon
MIDWESTERN
Glen Ullin
WBI
Grundy Ctr
NNG
Marshall
NNG
Charbonneau
WBI
Hazel
NNG
Aberdeen
NNG
Amana
NGPL
Milbank
NNG
Total Interstate Pipe
* Top 15
Name
Manhattan
North Hayden
Minooka
Troy Grove
Torrence
Clinton
Princeton
Prophetstown
Davenport
Iowa City
Trimont
Brandt
Warner
Watertown
Total LDC
LDC*
Pipe
INTEGRYS
NIPSCO
NICOR
NICOR
KM/INTEGRYS
INTERSTPOWER
AMEREN CILCO
INTERSTPOWER
MIDAMERICAN
MIDAMERICAN
HUTCHINSON
NWPUBLICSE
NWPUBLICSE
CITY WATERT
* Top 15
Mcf/d
600,000
545,000
400,000
400,000
360,000
134,000
120,000
120,000
100,000
100,000
60,000
38,000
24,000
22,000
3,688,470
Power Plant
Name
Pipe
Elwood
ELWOOD
Marshalltown
INTERSTPOWER
St Anthony
MON-DAK
Wilton Center
LINCOLN GEN
Elm Creek
GREAT RIVER
Yale
INTERSTPOWER
Lonesome Creek BASIN ELEC
Deer Creek
BASIN ELEC
Cordova
MIDAMERICAN
Groton
BASIN ELEC
Lanark
BASIN ELEC
Total Power Plant
Mcf/d
2,200,000
900,000
700,000
650,000
500,000
250,000
236,000
130,000
103,000
80,000
60,000
60,000
21,000
16,350
8,073
5,933,694
Mcf/d
420,000
228,000
200,000
190,000
180,000
130,000
125,000
95,000
53,000
46,000
46,000
1,713,000
Bison & The Rockies
Bison Pipeline Overview
Connecting The Rockies to Northern Border Pipeline
Montana
North Dakota
Kurtz
South Dakota
Buffalo
Wyoming
Rocky Mountain Production
12
Gas Production (Bcfd)
10
8
6
1
1.6
1.8
2.2
2.1
1
0.9
1.4
1.5
3.3
3.2
0.9
2016
0.9
1
1.3
2.5
2.4
1
1
1.4
2.6
1.8
1.8
2.1
2
0.9
0.9
1.5
1.6
3
2.8
0.9
1
2017
2018
1.7
1.6
2
1.9
1.9
0.9
0.8
0.7
0.7
1.6
1.6
1.7
1.7
1.7
2.7
2.6
2.4
2.3
2.2
2.1
1.2
1.4
1.5
1.6
1.7
1.8
1.8
2019
2020
2021
2022
2023
2024
2025
4
2
0
DJ
Greater Green River
Piceance
Uinta
Vertical
Williston
Source: WoodMac
Greater Green River
3.5
3
2.5
2
1.5
1
0.5
0
(Bcfd)
3.3 3.2
3
2.8 2.7
2.6
2.4 2.3
2.2 2.1
Source: WoodMac
1.2
1
0.8
0.6
Unita (Bcfd)
1.0 1.0 1.0
0.9 0.9 0.9 0.9
Piceance (Bcfd)
2
0.8
0.7 0.7
1.5
0.4
1
0.2
0.5
0
0
Source: WoodMac
1.6 1.6 1.6 1.7 1.7 1.7
1.4 1.4 1.5 1.5
Source: WoodMac
2
1.8
1.6
1.4
1.2
1
0.8
0.6
0.4
0.2
0
DJ (Bcfd)
1.4
1.5
1.6
1.7
1.8 1.8
1.2
0.9 0.9
1
Source: WoodMac
DJ Basin Production Forecast
DJ Basin
(Bcfd)
2
1.8
Source: WoodMac
1.6
PRB
1.4
1.4
1.2
1.2
1
0.8
0.6
0.4
0.2
Cheyenne
0
0.9 0.9
1
1.5
1.6
1.7
1.8 1.8
The Bakken
The Bakken… Where’s the drilling
North Dakota
North Dakota
January 11, 2016
The Bakken… Where’s the drilling
North Dakota
North Dakota
January 11, 2016
Bakken Rig Count ?
Source: North Dakota Industrial Commission,
Department of Mineral Resources, Oil and Gas Division
09/2015
Bakken Production Forecast
North Dakota Pipeline Authority (Wellhead Wet Gas)
Today
Bakken Flaring
Bakken Flaring
November, 2013
December, 2014
January 11, 2016
Montana
North Dakota
The Bakken
Gas Balance
Typical Gas Flows
February 2016
Production (wet gas)
Flared Gas (13%)
Tioga Lateral
Pecan Pipeline
Shrink
MMcfd
1,638
213
82
131
444
NBPL Interconnects
Stateline
Squaw Creek
Charbonneau
Rawson
Buford
Hay Butte
Spring Creek
Watford City
Roosevelt
Little Missouri
Killdeer (Aug 2016)
Glen Ullin
Total
Bakken
Max
Typical Capacity
Flows
MMcfd
137
180
64
95
50
60
126
405
34
48
5
50
252
446
35
60
6
50
39
100
0
96
20
100
768
1,690
Manning (Grasslands)
Hebron (Dakota Plant)
Kurtz (Bison)
Total
0
0
0
768
213
160
407
2,470
CS 6
Bakken Receipts
800
700
719
768
MMcfd
600
500
514
439
400
300
309
200
210
100
0
85
97
2009
2010
2011
2012
2013
2014
2015
2016
Projects - New Interconnects
•
Rawson (ONEOK)
•
•
•
•
Roosevelt
•
•
•
•
•
•
Receipt
50,000 Mcfd
Dec 18, 2015 In-Service
Receipt
96,000 Mcfd
Aug 2016 In-Service
Spring Creek
•
•
•
•
(Kinder Morgan)
Killdeer (ONEOK)
•
•
Receipt
405,000 Mcfd
Aug 13, 2015 In-Service
North Dakota
Montana
New
Interconnects
North Dakota
Montana
Upgrade
Receipt
446,000 Mcfd
July 2016 In-Service
Lonesome Creek
•
•
•
Upgrade
Delivery
65,000 Mcfd
October 20, 2015 InService
CS 5
CS 6
CS 6
CS 7
CS 8
Northern Border Pipeline
New Interconnects – Iowa
Minnesota
Wisconsin
Ledyard
Lakota
• Marshalltown (Interstate
Power & Light)
•
•
•
•
•
Delivery
Combined Cycle Power Plant &
LDC load
600 MW
228,000 Mcfd
Sept 11, 2015 In-Service
• Clinton (Interstate Power &
Light)
•
•
•
•
Delivery
Serving LDC load
134,000 Mcfd
Sept 1, 2016 In-Service
Yale
Ventura
Illinois
Ackley
Ackley
CS 14
Grundy
Beaman
Marshalltown
Tama
Amana
CS 16
Harper
Nebraska
Missouri
Iowa City
CS 17
North Dakota
• Hazel (Northern Natural Gas)
•
•
•
Delivery
60,000 Mcfd
Oct 30, 2015 In-Service
Minnesota
Northern Border Pipeline
New Interconnects – South Dakota
CS 9
CS 10
CS 11
Nebraska
Projects - The Bakken Header
Bakken Header
Bakken Header Alternative
• Northern Border to Tioga - 64 Miles
• Tioga to Stanley - 25 Miles
• 16” pipeline
• Up to 200 MMcfd Capacity
Montana
North Dakota
• Northern Border to Flat Irons - 25 Miles
• Flat Irons to Potential Plant - 10 Miles
• 16” pipeline
• Up to 200 MMcfd Capacity
County
Breakeven
Billings
$28
BOT-REN
$85
Burke
$82
Divide
$81
Dunn
$24
Golden Vall
$64
McKenzie
$27
McLean
$25
Mountrail
$43
Stark
$41
Williams
$38
North Dakota
Montana
By County
North Dakota
Bakken Breakeven Oil Prices
Burke $82
Divide $81
Mountrail $43
Williams $38
Williams $38
McKenzie $27
Bakken Header
Mountrail $43
Bakken Header Alt
McLean $25
McKenzie $27
McKenzie $27 Dunn $24
McLean $25
Billings $28
McKenzie $27
Dunn $24
Stark $41
Source: North Dakota
Department of Mineral
Resources Sept, 2015
BOT-REN $85
Billings $28
Questions ?
Northern Border Pipeline
Marketing Fundamentals and Supply Update
Jeff Nielsen
Director Short Term Marketing & Optimization
Discussion Points
• Supply Fundamentals
• Market Fundamentals
• Macro Economic Detail
• Value Overview
• Northern Border Opportunities
34
Supply Fundamentals
Northern Border - Supply Diversification
Average Flows
NORTHERN BORDER RECEIPT MIX - 2013
NORTHERN BORDER RECEIPT MIX - 2014
DAKOTA
GAS
4%
ROCKIES
2%
NORTHERN BORDER RECEIPT MIX - 2015
DAKOTA
GAS
4%
DAKOTA
GAS
5%
BAKKEN
16%
BAKKEN
23%
CANADIAN
78%
ROCKIES
9%
BAKKEN
31%
CANADIAN
60%
CANADIAN
63%
ROCKIES
5%
Source : Internal Analysis
36
Bakken Production Forecast
(Dry Gas)
2.0
1.8
1.6
1.4
0.9
•
0
0
0
0
2024
2025
1.0
0
0
0
0
0
0
2021
1.4
0.9
0.7
0.4
0.5
ACTUALS
NORTHERN
BORDER
1.4
2020
0.3
1.4
2019
0.2
1.2
1.3
2018
2010
0.1
0.1
2012
0.1
0.2
0.2
2011
0.2
0.3
1.1
1.3
2017
0.4
1.1
2015
0.4
2013
0.6
0.2
2016
0.6
0.2
2023
0.7
0.8
2022
1.0
2014
BcF/D
1.2
FORECAST
OTHER
FORECAST
FORECAST 1
FORECAST 2
FORECAST 3
Forecasted volumes are an average vendor increased/decreased production added to prior year (Based on Trend)
37
WCSB Production Forecast
20.0
18.0
16.0
14.0
13.6
13.7
13.4
13.5
13.5
14.3
13.8
14.0
14.2
2018
2019
2020
2021
15.5
16.0
16.4
2025
13.6
15.0
2024
13.6
2017
6.0
14.7
2016
8.0
2023
10.0
2022
BcF/D
12.0
4.0
2015
2014
2013
2012
2011
2010
2.0
ACTUALS
MARCELLUS/UTICA
ACTUALS
•
FORECAST
FORECAST
FORECAST 1
FORECAST 2
FORECAST 3
Forecasted volumes are an average vendor increased/decreased production added to prior year (Based on Trend)
38
Market Fundamentals
Deliveries to Northern Natural Gas Pipeline
SEASONAL DELIVERIES TO NORTHERN NATURAL GAS PIPELINE
1.80
1.60
1.40
1.54
1.52
1.44
1.51
BcF/D
1.20
1.00
1.17
1.10
1.05
0.80
0.60
0.40
0.20
-
W 12/13
S 13
W 13/14
S 14
W 14/15
S 15
W 15/16
WINTER MAXIMUM DELIVERIES TO NORTHERN NATURAL GAS
2.30
2.25
2.24
2.20
Deliveries into Northern Natural
follow consistent seasonal
volumes
•
However, W 15/16 experienced a
new record as deliveries from
Northern Border creped up to a
maximum of 2.26BcF
2.26
2.19
2.15
BcF/D
•
2.10
2.05
2.00
1.95
2.00
1.90
1.85
W 12/13
W 13/14
W 14/15
W 15/16
40
Pricing : Ventura Transport Value Comparison
$0.70
$0.67
$0.61
$0.58
$0.60
$0.55
$0.40
$0.34
$0.30
$0.23
$0.23
$0.20
$0.34
$0.30
$0.34
$0.27
$0.23
$0.23
$0.19
$0.23
$0.23
$0.19
$0.19
$0.12
$0.12
$0.11
$0.10
$0.03
W 16/17
S 17
W 17/18
S 18
NNG - NNG MIDCON
NNG - NNG MIDCON
AECO - VENTURA
NNG - NNG MIDCON
AECO - VENTURA
NNG - NNG MIDCON
AECO - VENTURA
NNG - NNG MIDCON
AECO - VENTURA
NNG - NNG MIDCON
S 16
AECO - VENTURA
$0.01
$0.00
$AECO - VENTURA
($$$) PER DtH
$0.50
W 18/19
41
Midwest Demand
POWER DEMAND
2.0
1.8
1.60
1.60
1.6
.1
.1
.3
.3
.3
.3
.3
.3
.3
.3
.3
.4
.4
.5
.5
.4
.5
.5
.5
.2
.2
.2
.3
.3
.3
.5
.5
.5
.5
.5
.5
.5
.5
2024
2025
4.20
4.20
4.20
4.20
4.20
4.20
.1
.3
.1
.3
.1
.3
.1
.3
.1
.3
.1
.3
.1
.3
.4
.4
.4
.4
.4
.4
.4
.5
.5
.5
.5
.5
.5
.5
.7
.7
.7
.7
.7
.7
.7
.9
.9
.9
.9
.9
.9
.9
1.3
1.3
1.3
1.3
1.3
1.3
1.3
2025
NORTH DAKOTA
2022
4.20
2024
IOWA
2023
MINNESOTA
.3
2023
WISCONSIN
2021
.1
.2
2020
.3
.1
.2
2022
ILLINOIS
.3
2021
INDIANA
.1
.3
2020
.3
.3
.3
.1
.3
2019
.2
.3
.2
2019
.1
.2
.1
.2
.3
1.70
.1
.1
2018
0.60
.1
.2
.1
.2
.3
1.70
.2
1.10
2017
.1
.1
.1
.2
0.60
.2
.2
1.80
2016
.1
.1
.1
.2
.2
2014
.2
0.50
2013
.4
0.50
2012
.6
2011
.8
.2
1.70
1.10
1.00
0.90
1.0
1.80
2015
1.2
2010
BcF/D
1.4
1.80
SOUTH DAKOTA
INDUSTRIAL DEMAND
4.5
.4
.5
.5
.5
.8
.8
.7
.8
.9
.9
.4
3.40
.1
.1
.4
.1
.1
.4
.1
.1
.4
.1
.1
.4
.1
.1
.4
.4
.5
.5
.5
.5
.5
.5
.5
.5
.5
.8
.8
.8
.8
.8
1.0
1.0
1.0
1.0
1.0
INDIANA
ILLINOIS
IOWA
MINNESOTA
.1
.2
.4
.5
.7
.8
1.2
2018
.5
.4
3.40
2017
1.0
.1
.1
.3
3.40
2015
1.5
.1
.1
.3
3.40
2014
2.0
.1
.1
.3
3.00
2012
2.5
3.10
2011
BcF/D
3.0
3.00
2010
3.5
3.30
2013
4.0
2016
3.90
WISCONSIN
NORTH DAKOTA
SOUTH DAKOTA
Source : Wood Mackenzie
42
Value Overview
Dollars($$$) Above/Below Max Rate
$(0.50)
S 16
W 16/17
S 17
W 17/18
S 18
$(0.95)
$(0.91)
$(0.69)
$(1.50)
$(1.56)
$(1.38)
$(1.52)
$(1.35)
$(1.37)
$(0.63)
$(0.44)
$(0.66)
$(0.40)
$(0.71)
$(0.30)
$(0.82)
$(0.87)
$(0.70)
$(0.78)
$(0.62)
$(0.64)
$(0.11)
$(0.18)
$(0.14)
$(0.10)
$(0.04)
$(0.05)
$0.50
$1.17
$1.27
$1.39
$0.03
$0.15
$0.09
$0.13
$0.01
$0.20
$0.15
$0.00
$0.07
$0.00
$0.13
$0.18
$0.23
$0.03
$0.30
$0.05
$0.31
$0.23
Pricing: Forward Canadian Dispatch Economics
Full Cost AECO Dispatch
$2.00
$1.50
$1.00
$-
$(1.00)
$(1.50)
$(2.00)
W 18/19
44
Pricing: AECO to Market Forward Values
VENTURA FORWARD VALUE
$4.00
$0.60
$3.50
$0.50
$0.40
$2.50
$2.00
$0.30
$1.50
$0.20
VALUE PER DtH
($$$) PER DtH
$3.00
$0.09
$0.43
$0.15
$0.48
$0.21
$0.50
$0.25
$0.54
$0.28
$0.53
$0.51
$0.50
$0.56
$1.00
$-
$0.10
$-
VALUE
AECO
VENTURA
MAX RATE
CHICAGO FORWARD VALUE
$3.50
$0.80
$3.00
$0.70
$0.40
$1.50
$0.30
$1.00
$-
$0.14
$0.33
$0.21
$0.39
$0.26
$0.41
$0.30
$0.46
$0.36
$0.48
$0.20
$0.59
$0.50
$0.68
($$$) PER DtH
$0.50
$2.00
VALUE PER DtH
$0.60
$2.50
$0.10
$-
VALUE
AECO
CHICAGO
MAX RATES
45
600%
0%
5790%
106%
52%
87%
W 15/16
BASIS
S 15
800%
W 14/15
400%
S 14
200%
W 13/14
BASIS
12/10/2015
11/10/2015
10/10/2015
9/10/2015
8/10/2015
7/10/2015
6/10/2015
5/10/2015
4/10/2015
3/10/2015
2/10/2015
1/10/2015
12/10/2014
11/10/2014
10/10/2014
9/10/2014
8/10/2014
7/10/2014
6/10/2014
5/10/2014
4/10/2014
3/10/2014
2/10/2014
1/10/2014
12/10/2013
11/10/2013
10/10/2013
9/10/2013
8/10/2013
7/10/2013
6/10/2013
5/10/2013
4/10/2013
3/10/2013
2/10/2013
1/10/2013
12/10/2012
11/10/2012
10/10/2012
9/10/2012
8/10/2012
7/10/2012
6/10/2012
5/10/2012
4/10/2012
3/10/2012
2/10/2012
1/10/2012
BASIS
$0.35
600%
$0.25
$0.15
500%
$0.05
400%
$(0.05)
300%
$(0.15)
200%
$(0.25)
100%
$(0.35)
0%
VOLATILITY
Pricing Volatility
Transportation Extrinsic Value
DAILY HENRY/VENTURA BASIS & VOLATILITY
VOLATILITY
SEASONAL HENRY/VENTURA BASIS & VOLATILITY
2000%
1800%
1600%
1400%
1200%
1000%
605%
VOLATILITY
46
Pricing: Historical Ventura to Chicago Value
DAILY VARIABLE COST CHICAGO VALUE
$0.20
VALUE PER DtH
$0.15
$0.10
$0.05
$$(0.05)
$(0.10)
$(0.15)
$0.20
80%
($$$) PER DtH
$0.16
70%
$0.14
$0.12
$0.09
$0.08
$0.11
$0.10
$0.08
$0.06
$0.08
$0.04
60%
50%
40%
30%
$0.05
$0.03
$0.04
20%
10%
$0.02
$-
2/29/2016
90%
$0.17
$0.18
$0.10
2/22/2016
2/15/2016
2/8/2016
2/1/2016
1/25/2016
1/18/2016
1/11/2016
1/4/2016
12/28/2015
12/21/2015
12/14/2015
12/7/2015
11/30/2015
MAX RATE
AUG 2015
SEP 2015
OCT 2015
NOV 2015
DEC 2015
JAN 2016
FEB 2016
MAR 2016
APR 2016
JUL 2015
AUG 2015
SEP 2015
OCT 2015
NOV 2015
DEC 2015
JAN 2016
FEB 2016
MAR 2016
MAX
MAX
RATES
% OF TIME AT MAX VALUE
VALUE
11/23/2015
11/16/2015
11/9/2015
11/2/2015
10/26/2015
10/19/2015
10/12/2015
10/5/2015
9/28/2015
9/21/2015
9/14/2015
9/7/2015
8/31/2015
8/24/2015
8/17/2015
8/10/2015
8/3/2015
$(0.20)
0%
% OF TIME
WITH-IN
$0.02 OF MAX
47
Macro Overview
Marcellus – Utica Production Forecast
MARCELLUS - UTICA PRODUCTION & FORECAST
60.0
50.0
38.5
39.6
40.6
41.7
43.1
2024
36.0
2023
23.4
33.1
2022
5.3
3.0
29.0
2020
10.0
8.3
19.1
15.9
11.7
2019
20.0
2021
30.0
2018
BcF/D
40.0
43.4
ACTUALS
2025
2017
2016
2015
2014
2013
2012
2011
2010
0.0
FORECAST
MARCELLUS/UTICA
ACTUALS
FORECAST
FORECAST 1
FORECAST 2
FORECAST 3
GULF COAST DEMAND FORECAST
(TEXAS & LOUISIANA)
35.0
30.0
GOLDEN PASS
CORPUS CHRISTI
FREEPORT
CAMERON
SABINE PASS
BcF/D
25.0
20.0
POWER
15.0
INDUSTRIAL
10.0
5.0
OTHER
2010
2011
2012
COMMERCIAL
2013
2014
RESIDENTIAL
2015
OTHER
2016
INDUSTRIAL
2017
POWER
2018
SABINE PASS
2019
CAMERON
2020
FREEPORT
2021
CORPUS CHRISTI
Forecasted volumes are an average vendor increased/decreased production added to prior year (Based on Trend)
Source : Wood Mackenzie
2022
2023
2024
2025
GOLDEN PASS
49
Mexican Demand
Gasoducto
Rosarita
350 Mmcfd
12.00
North
Baja
U.S. Southwest “pre-growth” export capacity
~1.7 Bcfd being expanded to 5 Bcfd
10.00
El Paso
Juarez, Samalayuca
& Norte Crossing
900 Mmcfd
4.00
2.00
2025
2024
2023
2022
2021
2020
2019
2018
2017
2016
2015
0.00
2014
Waha to
San Elizario
1.135 Bcfd
2013
CFE Proposed
0.55 Bcf
6.00
2012
El Paso
Into NW Mexico
360 Mmcfd
2011
Olgilby
614 Mmcfd
2010
Costa
Azul
BcF/D
8.00
Waha
South Texas “pre-growth” export capacity ~1.6
Bcfd being expanded to 4.1 Bcfd
Waha to Presidio
1.35 Bcfd
Webb Cnty
500 Mmcfd
(planned)
Topolobampo
South Texas
3.6 Bcfd
Mazatlan
50
Northern Border Capacity Update
Northern Border Available Capacity
• 2017
•
April maintenance capacity will be posted later in the
year
• Q4 2017
•
P-O-M to Ventura ~400 MMBtu/D *
•
P-O-M to Chicago ~33 MMBtu/D *
•
Ventura to Chicago ~61 MMBtu/D
*Capacity currently under ROFR
52
Factors Affecting Northern Border Value
• TransCanada mainline contracting
• Marcellus/Utica flows to Chicago & Midcontinent
• NGTL system dynamics
• NYMEX – Oil and Nat Gas drilling
• Level of LNG exports in the US and Canada
• WCSB storage inventory
53
Northern Border Pipeline
Maintenance Update
Garrett Word
Director, Commercial Design - US Pipelines
54
Significant Items
2015 - 2016 Winter Season
•
Winter 2015-16 weather was 14% warmer than
normal across NBPL markets.
•
Northern Border’s transmission peak day occurred on
January 16th with system deliveries of 2.9 Bcf.
•
The pipeline ran at a 82% load factor through Glen
Ullin during 2015.
55
Season To Date Heating Degree Day
Comparison
Minneapolis/St. Paul
8000
Chicago
7000
7000
6000
6000
5000
5000
2000
4,999
4,501
4,999
5,429
5,000
3000
5,887
5,790
5,080
5,790
6,202
3000
5,790
4000
7,047
4000
2000
1000
1000
0
0
2013-2014
2014-2015
STD ACTUAL HDD
30 Year Normal
2015-2016
2013-2014
2014-2015
2015-2016
* Minneapolis was 12% WTN for the Winter 15/16 vs. 7% CTN for Winter 14/15.
* Chicago was 10% WTN for the Winter 15/16 vs. 9% CTN for Winter 14/15.
56
Northern Border Winter Average Day
System Flows
2,600,000
2,400,000
2,200,000
2,000,000
1,800,000
Nov 2015
Flow Past Glen Ullin
Dec 2015
Flow Past Ventura
Jan 2016
Feb 2016
Flow Past Harper
847,740
541,295
568,963
389,263
423,187
354,905
0
372,505
200,000
610,704
400,000
622,234
600,000
878,890
800,000
2,425,208
1,000,000
2,486,360
2,521,004
1,200,000
2,088,555
1,400,000
2,082,314
Dth/day
1,600,000
Mar 2016
Capacity
57
Maintenance Schedule
Summer 2016
•
As has been done in the past, April and May have been
reserved for major planned outages and capacity impacting
events.
•
All gas fired compression will take a required, annual
maintenance outage during April and May. One station will be
taken offline at a time in order to minimize capacity impacts.
58
Maintenance Schedule
April and May 2016
Pipeline Integrity Work
NBPL will conduct Pipeline Integrity work
located between MLV74 to MLV75 Starting
April 19th – 22nd
Refer to Force Majeure Notice 1596
2016 Scheduled Spring Outages
April
Compressor Station 03 Spring Maint. 4/5 -4/6
Compressor Station 14 Spring Maint. 4/5 – 4/6
Compressor Station 13 Spring Maint. 4/7 – 4/8
Compressor Station 04 Spring Maint. 4/12 – 4/13
Compressor Station 16 Spring Maint. 4/12 – 4/13
Compressor Station 07 Spring Maint. 4/14 – 4/15
Compressor Station 17 Spring Maint. 4/19 – 4/20
Compressor Station 08 Spring Maint. 4/26 – 4/27
Compressor Station 18 Spring Maint. 4/26 – 4/27
Compressor Station 12 Spring Maint. 4/28 – 4/28
May
Compressor Station 11 Spring Maint. 5/3 – 5/4
Compressor Station 05 Spring Maint. 5/5 – 5/6
Compressor Station 12 Spring Maint. 5/10 – 5/11
Compressor Station 06 Spring Maint. 5/12 – 5/13
Compressor Station 09 Spring Maint. 5/17 – 5/19
Compressor Station 07 Spring Maint. 5/19 – 5/20
Compressor Station 01 Spring Maint. 5/19 – 5/20
Compressor Station 02 Spring Maint. 5/24 – 5/25
Compressor Station 10
Replace Compressor Station Discharge
Valve starting April 19th – 22nd
Refer to Force Majeure Notice 1596
59