Joe Pollard Director, Long Term Marketing. May 5, 2016

Transcription

1 Joe Pollard Director, Long Term Marketing May 5, 2016

2 Acquisition of Columbia Pipeline Group Strategic Rationale Premium natural gas pipeline and storage assets Extensive position in the Marcellus and Utica shale regions FERC regulated assets generate stable and predictable earnings and cash flow US$7.3 billion portfolio of growth initiatives and modernization investments Secures Incumbency Position in North America s Most Prolific Natural Gas Basins Illustrates the configuration of material systems within Columbia s natural gas pipeline network

3 Columbia Pipeline Group Asset Overview Columbia Gas Transmission 11,272 mile (18,141 km) FERC pipeline with average throughput of 3.9 Bcf/d 286 Bcf of working gas storage capacity Strong base business undergoing significant expansion to connect growing Marcellus/Utica supply Columbia Gulf Transmission 3,341 mile (5,377 km) FERC pipeline with average throughput of 1.5 Bcf/d System reversal and expansion offers competitive path to the Gulf Coast Premium Natural Gas Pipeline Network Millennium Pipeline (47.5% interest) 253 mile (407 km) FERC pipeline with average throughput of 1.1 Bcf/d Connects Pennsylvania supply to New York market Illustrates the configuration of material systems within Columbia s natural gas pipeline network

4 Combined Natural Gas Pipeline Footprint 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

5 Acquisition Key Takeaways Acquisition creates one of North America s largest regulated natural gas transmission businesses Complements our existing assets Adds to basin diversification and access to large markets Provides another platform for continued organic growth Agencies affirmed A credit rating following the announcement Builds on Track Record of Delivering Shareholder Value

6 Marketing Fundamentals and Supply Update May 5, 2016 Colin Strom Manager, Short Term Marketing & Optimization

7 Disclaimer : Forward Looking Information This presentation includes certain forward looking information to help current and potential investors understand management s assessment of our future plans and financial outlook, and our future prospects overall. Statements that are forward-looking are based on certain assumptions and on what we know and expect today and generally include words like anticipate, expect, believe, may, will, should, estimate or other similar words. Forward-looking statements do not guarantee future performance. Actual events and results could be significantly different because of assumptions, risks or uncertainties related to our business or events that happen after the date of this presentation. Our forward-looking information is based on the following key assumptions: inflation rates, commodity prices and capacity prices, timing of debt issuances financing and hedging, regulatory decisions and outcomes, foreign exchange rates, interest rates, tax rates, planned and unplanned outages and the use of our pipeline and energy assets, integrity and reliability of our assets, access to capital markets, anticipated construction costs, schedules and completion dates, land acquisitions and divestitures. Our forward looking information is subject to risks and uncertainties, including but not limited to our ability to successfully implement our strategic initiatives and whether they will yield the expected benefits, the operating performance of our pipeline and energy assets, economic and competitive conditions in North America and globally, amount of capacity sold and rates achieved in our pipelines business, the availability and price of energy commodities, the amount of capacity payments and revenues we receive from our energy business, regulatory decisions and outcomes, outcomes of legal proceedings, including arbitration, performance of our counterparts, changes in the political environment, changes in environmental and other laws and regulations, competitive factors in the pipeline and energy sectors, construction and completion of capital projects, cost for labor, equipment and material costs, access to capital markets, interest and foreign exchange rates, weather, cyber security and technological developments, and economic conditions in North America as well as globally. You can read more about these risk factors and others in reports we have filed with Canadian securities regulators and the U.S. Securities and Exchange Commission (SEC) and available at You should not put undue reliance on forward-looking information and should not use future-oriented information or financial outlooks for anything other than their intended purpose. We do not update our forward-looking statements due to new information or future events, unless we are required to by law. This presentation contains reference to certain financial measures (non-gaap measures) that do not have any standardized meaning as prescribed by U.S. generally accepted accounting principles (GAAP) and therefore may not be comparable to similar measures presented by other entities. These non-gaap measures may include Comparable Earnings, Comparable Earnings per Share, Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA), Comparable EBITDA, Earnings Before Interest and Taxes (EBIT), Comparable EBIT, Comparable Interest Expense, Comparable Interest Income and Other, Comparable Income Taxes and Funds Generated from Operations. Reconciliations to the most closely related GAAP measures are included in our most recent Management s Discussion and Analysis filed with Canadian securities regulators and the SEC and available at 7

8 Marketing Fundamentals & Supply Update GTN Overview North American Supply & Demand Supply Fundamentals Market Fundamentals Value Overview Opportunities & Impacts to GTN Value 8

9 GTN Overview

10 Operating Parameters Positioned to serve markets in California, Nevada, and the Pacific Northwest Consists of 1,350 miles of pipeline Capacity of 2.81 Bcfd at the U.S. border and 2.23 Bcfd at the California border Long-term contracts extending out to 2023 Volume throughput has been strong and growing through 2015/

11 North American Supply & Demand

12 North American Supply 2016 TransCanada Outlook 12

13 North American Demand 2016 TransCanada Outlook LNG Exports Bcfd Transport Power Generation Industrial Other Residential Commercial

14 Supply Fundamentals 1

15 Marcellus & Utica Production Forecast Bcfd ACTUALS MARCELLUS/UTICA ACTUALS FORECAST FORECAST FORECAST 1 FORECAST 2 FORECAST 3 15

16 San Juan & Permian Production Forecast SAN JUAN PRODUCTION & FORECAST 3.5 Bcfd SAN JUAN ACTUALS FORECAST FORECAST 1 FORECAST 2 FORECAST 3 PERMIAN PRODUCTION & FORECAST Bcfd PERMIAN ACTUALS FORECAST FORECAST 1 FORECAST 2 FORECAST 3 16

17 Rockies Production Forecast Bcfd ROCKIES ACTUALS FORECAST FORECAST 1 FORECAST 2 FORECAST 3 17

18 Western Canadian Production Outlook Bcfd ACTUALS WCSB ACTUALS FORECAST FORECAST FORECAST 1 FORECAST 2 FORECAST 3 18

19 NGTL Supply Debottleneck Rapid changes in WCSB supply created the need to address the system s export capability Successful open season will increase the firm subscription for export capability at the ABC gate (Coleman, AB) by ~150 MMcfd in Q Source: TransCanada Presentation; May 5,

20 Market Fundamentals

21 Demand Projections Pacific Northwest & California PaCNW 3,000 2,500 MMcF/D 2,000 1,500 1, ,811 2,675 1,669 1,970 1,613 2,122 1,557 2,121 1,608 2,278 1,776 2,331 1,797 2,321 1,790 2,349 1,798 2,373 1,740 2,360 1,749 2,349 1,740 2,352 1,758 2,380 - S 13 W 13/14 S 14 W 14/15 S 15 W 15/16 S 16 W 16/17 S 17 W 17/18 S 18 W 18/19 S 19 W 19/20 S 20 W 20/21 S 21 W 21/22 S 22 W 22/23 S 23 W 23/24 S 24 W 24/25 S 25 W 25/26 ACTUALS FORECAST ACTUALS FORECAST FORECAST 1 FORECAST 2 CALIFORNIA 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1,000 - S 13 W 13/14 S 14 4,761 4,688 5,079 4,901 4,800 5,212 4,769 5,153 4,656 5,090 4,577 4,971 4,495 4,904 4,455 4,934 4,469 W 14/15 4,954 S 15 4,424 W 15/16 4,911 S 16 4,424 W 16/17 4,905 S 17 4,404 W 17/18 4,952 S 18 MMcF/D 4,449 4,974 W 18/19 S 19 W 19/20 S 20 W 20/21 S 21 W 21/22 S 22 W 22/23 S 23 W 23/24 S 24 W 24/25 S 25 W 25/26 ACTUALS FORECAST ACTUALS FORECAST FORECAST 1 FORECAST 2 21

22 California Storage PG&E HISTORICAL STORAGE BALANCE 250, ,000 MMcfd 150, ,000 50, , , , ,460 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC 5 YR - RANGE YR - AVERAGE 2015 SoCAL HISTORICAL STORAGE BALANCE MMcfd 160, , , ,000 80,000 60,000 40,000 20, ,952 59,935 59,240 58,469 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC 5 YR - RANGE YR - AVERAGE

23 Hydro Outlook Pacific Northwest & California Stronger hydro conditions than 2015, but unseasonably warm temperatures are causing a quick runoff Water supply forecasts continue to rapidly deteriorate with early runoffs depleting mountain snowpack Early Q2 snowpack levels are falling to 25-50% of normal for late April 10 YEAR HYDRO OUTPUT STUDY KCFS JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC RANGE YR AVERAGE

24 Washington Snow Water Equivalent 24

25 Oregon Snow Water Equivalent 25

26 Peak Summer Weather Forecast NOAA June to August MDA Weather Services June to August Source: NOAA and MDA Weather Services 26

27 Redwood Path Maintenance Redwood Path Maintenance Dates Capacity (MMcf/d) % of Max Maintenance Notes 20-Apr % Delevan Station Maintenance 28-Apr % Tionesta Station Maintenance 3-May % Delevan Station Maintenance 4-May % Gerber Station Maintenance 5-May % Gerber Station Maintenance 10-May % Tionesta Station Maintenance 11-May % Burney Station Maintenance 12-May % Burney Station Maintenance 17-May % Delevan Station Maintenance 18-May % Delevan Station Maintenance 19-May % Delevan Station Maintenance Source: 27

28 New Market Demand Projections Carty Lateral New lateral to serve NW power generation 175 MMcfd of lateral capacity and 75 MMcfd of GTN mainline capacity 440 MW expected in-service for Q Jordan Cove & Pacific Connector Just signed a 20yr agreement with Itochu Corp. (Japanese firm) Appealing FERC s Denial (March 2016) 1 Bcfd facility in-service in Q1-Q Northwest Innovation Works Plan to build three Methanol Plants (~$1B each) with two moving forward Each plant will have two trains with ~120 MMcfd of natural gas load Earliest In-service date of 2019 Trails West Pipeline Cross Cascades link to serve growing power/industrial demand along the I-5 corridor Compression based expandability to 750 MMcfd with expected in-service in Q

29 Mexican Natural Gas Demand Gasoducto Rosarita 350 MMcfd North Baja U.S. Southwest pre-growth export capacity ~1.7 Bcfd being expanded to 5 Bcfd Costa Azul Olgilby 614 MMcfd El Paso Into NW Mexico 360 MMcfd El Paso Juarez, Samalayuca & Norte Crossing 900 MMcfd CFE Proposed 0.55 Bcf Waha to San Elizario Bcfd Waha Waha to Presidio 1.35 Bcfd Webb Cnty 500 Mmcfd (planned) South Texas pre-growth export capacity ~1.6 Bcfd being expanded to 4.1 Bcfd Topolobampo South Texas 3.6 Bcfd Mazatlan

30 Current Volumetric Flow Pacific NW Deliveries KINGSGATE MDthd JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC 5-YEAR RANGE MDthd Malin Deliveries JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC 5-YEAR RANGE MDthd JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC YEAR RANGE

31 Value Overview

32 Daily Transportation Values to Malin 32

33 Forward Pricing AECO Malin Value MALIN FORWARD VALUE ($$$) PER DtH $0.90 $0.80 $0.70 $0.60 $0.50 $0.40 $0.30 $0.20 $0.10 $- $0.62 $0.67 $0.70 $0.78 $0.71 $0.63 $0.50 $0.50 $0.61 $0.60 $0.59 $0.58 $0.32 $0.34 $0.39 $0.50 $0.46 $0.45 VALUE MAX RATE MALIN FORWARD VALUE $0.70 $0.60 $0.50 ($$$) PER DtH $0.40 $0.30 $0.20 $0.10 $0.66 $0.57 $0.40 $0.48 $0.32 $0.37 $0.21 $0.34 $- VALUE MAX RATE 33

34 Forward Pricing to Malin AECO (vs) Rockies $1.20 $1.14 $1.14 $1.14 $1.14 $1.14 $1.14 $1.14 $1.14 $1.00 $0.80 ($$$) PER DtH $0.60 $0.40 $0.30 $0.30 $0.30 $0.30 $0.30 $0.30 $0.30 $0.30 $0.20 $- $0.66 $(0.01) $0.57 $(0.01) $0.40 $0.03 $0.48 $0.03 $0.32 $0.03 $0.37 $0.00 $0.21 $0.01 $0.34 $(0.01) $(0.20) AECO - GTN OPAL - RUBY AECO - GTN OPAL - RUBY AECO - GTN OPAL - RUBY AECO - GTN OPAL - RUBY AECO - GTN OPAL - RUBY AECO - GTN OPAL - RUBY AECO - GTN OPAL - RUBY AECO - GTN OPAL - RUBY S 16 W 16/17 S 17 W 17/18 S 18 W 18/19 S 19 W 19/20 34

35 Forward Pricing Canadian Dispatch Economics Full Cost AECO Dispatch $2.00 Dollars ($$$) Above/Below Max Rate $1.50 $1.00 $0.50 $- $(0.50) $(1.00) $(1.50) $(2.00) $0.27 $0.10 $0.18 $0.02 $0.07 $(0.09) $0.09 $(0.04) $0.15 $(0.12) $(0.12) $(0.23) $0.38 $0.15 $0.35 $0.08 $0.30 $0.01 $0.20 $0.11 $0.13 $0.02 $0.07 $(0.05) $(0.53) $(0.68) $(0.65) $(0.77) $(0.78) $(0.90) $(0.54) $(0.38) $(0.73) $(0.39) $(0.59) $(0.41) $(1.26) $(1.43) $(1.39) $(1.52) $(1.52) $(1.66) $1.61 $(0.91) $1.48 $(1.00) $1.36 $(1.11) W 16/17 S 17 W 17/18 S 18 W 18/19 S 19 35

36 Opportunities & Factors Impacting GTN Value

37 Opportunities & Impacts to GTN Value Supply fundamentals Alberta eastern gate exports to NBPL and TCPL Mainline NGTL export enhancements for Q and potential 2018/2019 Northwest loads Flow displacements around Marcellus/Utica basins Competition for supplies in the southwest and Mexico California impacts of Aliso Canyon and San Onofre Park & Loan services 37

38 GTN Annual Customer Meeting - NGTL Update May 5, 2016 Jawad Masud Director of Commercial West Markets for NGTL/Foothills

39 Forward Looking Information and Non-GAAP Measures This presentation includes certain forward looking information to help current and potential investors understand management s assessment of our future plans and financial outlook, and our future prospects overall. Statements that are forward-looking are based on certain assumptions and on what we know and expect today and generally include words like anticipate, expect, believe, may, will, should, estimate or other similar words. Forward-looking statements do not guarantee future performance. Actual events and results could be significantly different because of assumptions, risks or uncertainties related to our business or events that happen after the date of this presentation. Our forward-looking information is based on the following key assumptions: inflation rates, commodity prices and capacity prices, timing of financings and hedging, regulatory decisions and outcomes, foreign exchange rates, interest rates, tax rates, planned and unplanned outages and the use of our pipeline and energy assets, integrity and reliability of our assets, access to capital markets, anticipated construction costs, schedules and completion dates, acquisitions and divestitures. Our forward looking information is subject to risks and uncertainties, including but not limited to: our ability to successfully implement our strategic initiatives and whether they will yield the expected benefits, the operating performance of our pipeline and energy assets, economic and competitive conditions in North America and globally, the availability and price of energy commodities and changes in market commodity prices, the amount of capacity sold and rates achieved in our pipeline businesses, the amount of capacity payments and revenues we receive from our energy business, regulatory decisions and outcomes, outcomes of legal proceedings, including arbitration and insurance claims, performance of our counterparties, changes in the political environment, changes in environmental and other laws and regulations, construction and completion of capital projects, labour, equipment and material costs, access to capital markets, interest and foreign exchange rates, weather, cyber security and technological developments. You can read more about these risks and others in our Fourth Quarter 2015 Financial Highlights release and 2015 Annual Report filed with Canadian securities regulators and the U.S. Securities and Exchange Commission (SEC) and available at As actual results could vary significantly from the forward-looking information, you should not put undue reliance on forward-looking information and should not use future-oriented information or financial outlooks for anything other than their intended purpose. We do not update our forward-looking statements due to new information or future events, unless we are required to by law. This presentation contains reference to certain financial measures (non-gaap measures) that do not have any standardized meaning as prescribed by U.S. generally accepted accounting principles (GAAP) and therefore may not be comparable to similar measures presented by other entities. These non-gaap measures may include Comparable Earnings, Comparable Earnings per Share, Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA), Comparable EBITDA, Earnings Before Interest and Taxes (EBIT), Comparable EBIT, Distributable Cash Flow, Comparable Distributable Cash Flow, Distributable Cash Flow per Share, Comparable Distributable Cash Flow per Share, Comparable Interest Expense, Comparable Interest Income and Other, Comparable Income Tax Expense, Comparable Net Income Attributable to Non-Controlling Interests, Comparable Net Income from Equity Investments, Comparable Depreciation and Amortization, and Funds Generated from Operations. Reconciliations to the most closely related GAAP measures are included in our Fourth Quarter 2015 Financial Highlights release filed with Canadian securities regulators and the SEC and available at

40 NGTL System 32,000+ km of pipe combined assets of NGTL and ATCO Pipelines Over 1100 receipt and 1000 delivery points on system Transports approximately 75% of WCSB production Over 1000 Tcf of WCSB resource 400+ Bcf of WCSB gas storage > 50 Bcf/d of NIT trading liquidity System Annual Revenue Requirement of ~ $1.85 billion $7.2 billion investment base Regulated by the National Energy Board

41 WCSB Gas Supply Historical Forecast

42 WCSB Wells Drilled and Remaining Resource Estimates WCSB Remaining Resource Estimates Montney 1018 Deep Basin Year Drilled 172

43 WCSB Supply/Demand & Export Flows Bcf/d History Forecast WCSB Supply Other WC Demand No LNG World? WC Oil Sands Demand Delayed LNG? BC Coast LNG Exports WCSB Exports

44 NGTL System Receipt Flows??? 2014/ /16 Forecast Excluding Storage

45 NGTL System Intra Basin Flows Daily Delivery Annual Average Forecast Steady increase in intra-basin demand Predictable seasonal variations Further stimulus for oil related demand growth

46 East Gate Historic and Current Flows Bcf/d Bcf/d

47 EGAT Firm Contracts and Capability

48 WGAT Flows

49 West Path Firm Contracts and Capability Capability April 2016 (Bcf/d) Capability Nov 2018 (Bcf/d) GTN Foothills -BC A/BC Border Note: Values are estimated.

50 Working Gas in Storage Connected to NGTL System Historic Maximum Inventory 69 Bcf Storage Locations If we continue to inject at the average rate of injection April 1-10 (856 mmcf/d), storage will reach the historic maximum before the end of June 2016.

51 Monthly Outage Forecast - April

52 Monthly Outage Forecast - April

53 NGTL System Settlements 2015 Settlement: 10.1% return on equity and 40% equity thickness 3.17% composite depreciation rate OM&A sharing mechanism with collars allocating risks/rewards $220 million fixed OM&A threshold 2016/17 Settlement: Continuation of 2015 cost of capital and depreciation rates Same OM&A collar structure $222.5 million fixed OM&A threshold each year NEB approved the Settlement on April 7, 2016 OM&A Sharing Mechanism 100% NGTL 75/25 Sharing NGTL and Shippers 50/50 Sharing NGTL and Shippers 2014 actual OM&A plus 4.5% = $220 MM /50 Sharing NGTL and Shippers 75/25 Sharing NGTL and Shippers + $5 MM + $5 MM 2016/2017 $222.5 MM - $5 MM - $5 MM 100% NGTL

54 NGTL Revenue Requirement and System Tolls $mm +/- 2 * *2016 Interim Tolls

55 NGTL System Growth Through Expansion Facilities ~$300 million capital additions 28 km NPS 24 pipelines 3.5 MW compression 15 meter stations Expansion Facilities ~$5.3 billion capital additions Over 900 km NPS pipelines ~ 240 MW compression Over 50 meter stations > 6.0 Bcf/d incremental firm contracts 2015 Facilities 2016 Facilities 2017 Facilities 2018 Facilities NMML Facilities

56 Pipeline Integrity Program: Progressing as Planned By end 2016: ~ 9850 km assessed 39% NGTL assessed (increase from 27% at the start of AAP) $303 million in 2015 Similar spend in 2016 ILI and Tether Met all Commitments to date, on schedule for future commitments Organizational realignment of Integrity Management to include functions of planning, engineering and project management 56

57 2015 and 2016 Pipeline Integrity Program Overview Launcher/Receiver Pairs 66 Inline Inspections 500 Post ILI Digs/Repairs Launcher/Receiver Pairs 65 Inline Inspections Post ILI Digs/Repairs Launcher/Receiver/Mods Local or no impact Potential area/border impact Probable area/border impact Inline Inspections Local or no impact Potential area/border impact Probable area/border impact L&R, Mods Inline Inspections Operational capability timing and impacts are provided in MOF charts 57

58 THANK YOU!

59 Operational Highlights Paul Oliver USPL Operations Control 59

60 Recap of Operations GTN experienced its Peak Day on August 25 th, 2015, with total physical deliveries of 2.2-MMDth. There have been no unplanned outages resulting in nomination cuts on either GTN or Tuscarora since June

61 GTN Average Day System Throughput 61

62 Tuscarora Average Day System Throughput 62

63 North Baja Average Day System Throughput 63

64 GTN Power Loads 64

65 GTN Power Plant Connections Carty Generating (Proposed) Carty Lateral (Proposed) 6 CS CS8 Stanfield Coyote Springs Lateral Power Plants 1. Lancaster LLC 2. Rathdrum CT 3. Calpine HPP 4. Hermiston Generating 5. Coyote Springs I 6. Coyote Springs II 7. Klamath Cogen 8. Klamath Expansion Legend Power Plant Compressor Station Major R/D Point 65

66 Tuscarora Power Load 66

67 2016 GTN Maintenance Schedule Pipeline Integrity Digs A-Line EXT.02 MLV 8.4 September TBD 200 MMcf/d (leaving 2,530-MMcf/d available) Pipeline Inline Inspection (EMAT) A-Line CS03 to CS06 July MMcf/d (leaving 1,930 available) Compressor Station 14 MCC Upgrade MCC Replacement October (TBD) Lower than normal pressures into Malin PG&E 500-MMcf/d (leaving 1,610-Mmcf/d available) 67

68 2016 Maintenance Schedule Tuscarora & North Baja No Maintenance Scheduled that will impact capacity 68

69 Questions 69

70 Guest Speaker Mr Dennis Gartman Editor/Publisher The Gartman Letter 70

71 GTN Shipper Meeting Business Development May 5, 2016

72 I D A H O Trail West Pipeline 106 mile, 30 pipe Victoria Sumas W A S H I N G T O N Northwest Pipeline Sandpoint Supply receipt from GTN mainline near Madras Seattle Yakima Spokane Delivery points into NW Natural and Northwest Pipeline at Molalla Portland Pasco Walla Walla Lewiston Industrial developments and system reliability Salem Trail West Molalla Redmond Bend $800 MM (US $2021) Illustrative rates: $ $0.525 In-Service: Nov. 2021

73 The Integrated Project Concept Sumas Kingsgate Transportation Segments Molalla 4 3 Trail West 1 2 Madras Stanfield 1 NWP Gorge Capacity 2 GTN Capacity 3 Trail West Pipeline Capacity 4 NWP Expansion Capacity: I-5 Corridor Malin Ruby Opal REX 73