Outlook for the North American and Ontario Gas Markets Union Gas Customer Meeting London, Ontario June 5, 2014 Presented by: Frank Brock Senior Energy Market Specialist ICF International Frank.Brock@ICFI.COM 703.218.2741
Contents North American Market Overview Recent Market Trends ICF Market Projections Outlook for the Ontario Market 2
Extremely Cold Winter Weather Reduced Working Gas Levels To an 11 Year Low 4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 Source: EIA U.S. Natural Gas Storage Working Gas Levels (Tcf) Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Range, 2007-2011 Average, 2007-11 2012 2013 2014 Cold weather this past winter increased storage withdrawals and brought current working gas levels well below five-year average. End of season storage levels have not been below 1 Tcf since 2003, when the market had considerably less storage capacity than today. Working gas levels are projected to end the 2014 injection season at around 3.5 Tcf. 2014 ICF International. All rights reserved. Section 1, Page 3
Jan-13 Apr-13 Jul-13 Oct-13 Jan-14 Apr-14 Jul-14 Oct-14 Jan-15 Apr-15 Jul-15 Oct-15 Jan-16 Apr-16 Jul-16 Oct-16 Assuming Normal Weather, Near-term Gas Prices are Expected to Decline Assuming normal weather, ICF projects spot prices average about $4.50/MMBtu through the end of 2014. On average, ICF s 2014 prices are about $0.25 lower than the futures market. In 2015, ICF s projection averages $3.80, or about $0.40 below the current futures prices. Assuming normal weather and continued production increases, ICF expects price to decline in 2015. However, by 2016 increased demand growth is likely to place upward pressure on prices. $6.00 $5.00 $4.00 $3.00 $2.00 $1.00 Historic and Projected Henry Hub Natural Prices Nominal Dollars per MMBtu ICF Projection May 23, 2014 Futures Historic 2014 ICF International. All rights reserved. 4
Gas-directed Rig Count is Low, but Gas Production Remains Strong Since 2012, gas-directed rig activity has been declining as producers shift rigs to liquids-rich plays. Currently, less than 20% of the active rigs are gas-directed. However, the low rig count is only part of the story. Over 30% of the gas-directed rigs are operating in the Marcellus and Utica play areas. The practice of drilling multiple wells per pad means each active rig can drill more wells per year. Producers are increasing perwell production by drilling longer horizontal segments with more fracking stages. 2,000 1,500 1,000 500 0 U.S. Oil & Gas Rig Count* * Source: Baker Hughes 2014 ICF International. All rights reserved. Section 1, Page 5 Oil Gas 1000 U.S. Gas-Direct Rigs by Play Area* 750 500 250 0 Marcellus & Utica All Other
Marcellus and Utica Growth Continues Unabated Despite a slight decrease in the Marcellus Shale rig count over the past year, production has continued to increase. More well are being drilled per active rig, and production per well has continued to increase. Wells in the Utica Shale have had higher gas-to-oil production ratio than earlier expected. Total Marcellus and Utica gas production now projected to reach 20 Bcfd by 2016, 30 Bcfd by 2025, and 34 Bcfd by 2035. Together, these two plays account for nearly 80% of incremental production in North America. 40 35 30 25 20 15 10 5 0 Marcellus and Utica Projected Gas Production (Average Bcfd) 2006 2010 2013 2020 2025 2030 2035 Marcellus Utica 2014 ICF International. All rights reserved. 6
Marcellus and Utica Growth Driving Pipeline Additions and Reversals As production out of Marcellus and Utica continues to grow, more pipeline capacity will be needed to carry these supplies to market. New capacity is being added, and many of the pipelines that traditionally moved gas into the Northeast have announced plans to reverse. In total, about 16 Bcfd of new or reverse capacity will be added by end of 2017. However, since many of these projects feed into each other, the incremental capability to transport gas from Marcellus and Utica is closer to 9 Bcfd. Company - Project Name Capacity (MMcfd) Planned In Service Status Dominion Transmission - Natrium-to-Market 185 2014 FERC Approved ANR Pipeline - Lebanon Lateral Reversal 350 2014 Planned ANR Pipeline - Southeast Mainline System Reversal 600 2015 Announced Texas Eastern - TEAM 2014 600 2014 Under Construction Texas Eastern - Ohio Pipeline Energy Network (OPEN) 550 2015 FERC Approved Texas Eastern - Uniontown to City Gas 425 2015 Planned Algonquin - AIM Project 342 2016 Filed with FERC Spectra - NEXUS Gas Transmission 1000 2017 Announced Texas Eastern - Gulf Markets - North to South 415 2017 Announced National Fuel - Mercer Expansion Project 105 2014 Under Construction National Fuel - West Side Expansion 95 2015 Filed with FERC National Fuel - Northern Access 2015 140 2015 Filed with FERC Empire Pipeline - Central Tioga County or (TCE2) 260 2015 Announced Tennessee Gas Pipeline - Rose Lake Expansion Project 230 2014 Under Construction Tennessee Gas Pipeline - Broad Run Flexibility Project 590 2015 Announced Tennessee Gas Pipeline - Broad Run Expansion Project 200 2017 Announced Rockies Express Pipeline - East to West Project 1800 2015 Announced Iroquois Gas Transmission - Wright Interconnect Project 650 2015 Filed with FERC Columbia Gas Transmission - West Side Exp - Smithfield III 444 2014 Under Construction Columbia Gas Transmission - East Side Exp 310 2015 Under Construction Columbia Gas Transmission - Leach Express 1500 2016 Announced Columbia Gulf Transmission - Rayne Express 1500 2016 Announced Millennium Pipeline - Hancock Compression 108 2014 Under Construction Williams Transcontinental - Leidy Southeast 525 2015 Filed with FERC Williams/Cabot Oil/Piedmont Nat Gas - Constitution Pipeline 650 2015 Filed with FERC Williams Transcontinental - Virginia Southside Expansion 270 2015 Under Construction Williams Transcontinental - Atlantic Sunrise 1700 2017 Announced Texas Gas Transmission - Ohio-Louisiana Access Project 600 2016 Announced 2014 ICF International. All rights reserved. Section 1, Page 7
Long-term Demand Growth is Driven the Power Sector and Exports By 2035, U.S. and Canadian gas consumption is projected to increase by nearly 10 Tcf, an average growth rate of about 1.3% per year. Over 70% of the consumption growth comes from the power sector, which grows to nearly 16 Tcf. Gas exports via new LNG terminals and by pipeline to Mexico will create additional demand growth through 2020. 50 45 40 35 30 25 20 15 10 5 U.S. and Canadian Gas Demand (Tcf per year) Mexico Exports Power Industrial (Petrochem) Industrial (All Other) Commercial Residential LNG Exports Other 0 2010 2015 2020 2025 2030 2035 2014 ICF International. All rights reserved. 8
Exports are Expected to be Major Drivers of Future Demand Growth Since 2012, DOE has approved non- FTA exports for 6 U.S. LNG terminals: Sabine, Freeport, Lake Charles, Cove Point, Camron LNG, and Jordan Cove. ICF s current projection assumes U.S. LNG exports reach 6.6 Bcfd by 2020. Another 2.7 Bcfd of LNG exports from British Columbia. Recent growth in Mexican exports has been driven by increases in Eagle Ford production and growth in Mexican gas use. Exports to Mexico are projected to reach almost 5 Bcfd by 2030. 10 8 6 4 2 0 U.S. and Canadian LNG Exports, Average Bcfd British Columbia US East Coast US Gulf Coast 2013 2015 2020 2025 2030 2035 5 4 3 2 1 US Exports to Mexico, Average Bcfd 0 2013 2015 2020 2025 2030 2035 California West Texas/New Mexico Arizona South Texas 2014 ICF International. All rights reserved. 9
Marcellus is the Largest and Fastest Growing Play, but Significant Growth in Other Plays Too Total U.S. and Canada shale gas production is projected to increase from nearly 11 Tcf in 2012 to 29 Tcf in 2035. Western Canadian shale plays include Montney, Horn River, Cordova & Liard. Eagle Ford is attractive because of its high liquids content, and also for exports to Mexico. Haynesville likely to resume growth as LNG export terminals come on-line. U.S. and Canada Shale Gas Production (Tcf) W. Canada Eagle Ford Marcellus Haynesville 1/ Haynesville production includes other shales in the vicinity, e.g., the Bossier Shale 2014 ICF International. All rights reserved. 10
Changes in Supply and Demand Will Significantly Change Pipeline Flows Over the Next 10 Years Robust Marcellus gas production growth displaces gas flow from the gulf coast such that many gulf coast to northeast pipelines will have prevailing reversed direction flow by 2017. Marcellus gas will reach Eastern Canada through Michigan and New York. Declining conventional production in Alberta and increasing gas consumption for oil sands development reduces flows from Western Canada. Source: ICF International 2014 ICF International. All rights reserved. 11
Gas Prices Remain Relatively Low in the Near Term, but Increase as the Market Grows $10 $9 $8 $7 $6 $5 Annual Average Henry Hub Price (2012$/MMBtu) Cold Winter Pops 2014 Gas Price Demand Surge & LNG Exports Ramp Up Nuclear Retirements $4 Stable Prices $3 Market Growth and 2013: Perfect Supply $2 Supply Growth in Storm Leads to Rationalization Lockstep Unsustainably $1 Low Gas Prices $0 2005 2010 2015 2020 2025 2030 2035 Historical ICF Projected 2014 ICF International. All rights reserved. 12
Basis Trends are Influenced by Regional Supply and Demand Shifts, but Also Reflect Added Gas Infrastructure Average Basis (2012$/MMBtu) 2001 to 2013 2014 to 2020 2021 to 2030 Henry Hub to NYC 1.19 1.50 0.87 Henry Hub to Dominion North Point 0.32-0.11-0.37 Henry Hub to Dominion South Point 0.34-0.01-0.28 Henry Hub to Chicago -0.01 0.32 0.07 Henry Hub to Dawn 0.25 0.75 0.45 Henry Hub to South Florida 0.61 0.37 0.48 AECO to Chicago 0.81 0.81 0.50 Opal vs Henry Hub 1.16 0.23 0.36 Opal to Dominion North Point 1.48 0.12-0.01 Opal to Dominion South Point 1.50 0.22 0.08 Opal to Southern California 1.17 0.22 0.28 Southern California vs Henry Hub -0.01 0.01 0.08 Midcontintent vs Henry Hub 0.54 0.07 0.16 East Texas vs Henry Hub 0.22 0.08 0.10 San Juan Basin vs Henry Hub 0.87 0.23 0.31 2014 ICF International. All rights reserved. 13
Near-term Prices Likely to Remain Around $4, but Rise to $5-$6 as Demand Grows Despite major cuts in gas-directed drilling over the past year, productivity continues to increases in the shale plays (especially the Marcellus), which has helped hold down prices. Near-term gas prices get a boost from the cold winter and subsequent storage refill. Projected Henry Hub gas prices are likely to average $5-$6 per MMBtu in the longer term; high enough to support projected supply development, but not so high as to adversely impact market growth. Continued regional shifts in gas supply and demand will drive future gas infrastructure needs. New transportation services are needed to support both demand and supply growth, but supply and demand shifts will change infrastructure utilization over time. 2014 ICF International. All rights reserved. 14
Outlook for the Ontario Market
US$/MMBtu Dawn Spot Prices Averaged Over $10/MMBtu this Winter, and Peaked at Nearly $50/MMBtu $60 $50 $40 Dawn AECO Dominion SP Henry Hub $30 $20 $10 $0 2014 ICF International. All rights reserved. 16
Current Status of the TCPL Settlement The NEB s March 2013 restructuring decision put TCPL at risk for revenues, but also gave TCPL significant tools to price discretionary services in order to maximize revenues TCPL is using these tools to shift shippers from IT and STFT to long-haul FT capacity, rather than rely on short-term FT or IT capacity, Under the March 2013 Decision, TCPL stated that is would not to expand capacity through the Parkway- Maple constraint, effectively forcing more shippers to contract for FT back to Empress. This continuing constraint risked the isolation of the Dawn Hub. TCPL and the LDCs signed a settlement agreement in September, and TCPL submitted it to the NEB in December 2013. In March 2014, NEB announce it would not accept the initial application; TCPL filed additional evidence in May, and a hearing is set for September. While multiple regulatory approvals are still required, the settlement agreement: Provides TCPL with more assurance that it will be able to recover costs. Requires TCPL to build through the Parkway-Maple constraint, thereby providing greater flexibility for shippers to contract short-haul capacity. Prohibits LDCs from building capacity to by-pass TCPL within the Eastern Ontario Triangle. After the end of the agreement in January 2021, TCPL will provide separate tolls for the long haul segments (Prairies segment and Northern Ontario Line) versus the short-haul segments (within the Eastern Ontario Triangle). The settlement agreement does not address the proposed conversion of some of TCPL s mainline capacity from gas to oil (the Energy East project). 2014 ICF International. All rights reserved. 17
Potential Impacts of Energy East Project TCPL s Energy East project proposes to remove approximately 1 Bcfd of capacity from service from Alberta through eastern Ontario. If the Energy East proceeds, the net capacity remaining on the TCPL mainline would be about 300 MMcfd below what is currently contracted; last winter, all of the current capacity was used on peak winter days. New pipeline capacity would be needed to serve existing contracted demand. Under the old NEB restructuring decision, shippers using that capacity would likely need to contract back to Empress for supplies. If the new settlement agreement is approved, likelihood of shippers contracting back to Dawn instead of Empress would increase. GAS-TO-OIL LINE CONVERSION NEW OIL PIPE NEW GAS CAPACITY NEEDED TERMINAL 2014 ICF International. All rights reserved. Source: National Post 18
New Capacity in the U.S. Will Allow More Marcellus Gas to Move To Ontario Over the past 2 years, capacity expansions by Tennessee, Dominion, National Fuel, and Empire have made it easier to move Marcellus gas to western New York and to the Niagara border point. The proposed NEXUS Gas Transmission pipeline would allow additional Marcellus and Utica production to move to Dawn. However, existing pipeline constraints within Ontario will have to be relived to make effective use of these new supplies within the province. 2014 ICF International. All rights reserved. 19
Flows From Western Canada Continue to Decline, but Opportunities for New Supplies Are Increasing Inter-regional Pipelines Flows in 2025, MMcfd 2014 ICF International. All rights reserved. 20
Coal Plant Shutdowns have Boosted Gas Demand in the Power Sector In April 2014, Ontario became the first jurisdiction in North America to fully eliminate coal as a source of electricity generation. Bout 10 GW of new natural gas-fired has been added to replace the retired coal capacity. From 2007 to 2012, gas-fired generation increased from about 10% to over 20% of Ontario s total generation. Ontario s wind capacity has also grown from 400 MW of six years ago to about 2,000 MW today. By 2030, wind is projected to provide 10 percent of the province's generation. The increased use of wind creates additional need for firming generation from gas generators. The majority of Ontario s electricity supplies still comes from nuclear and hydropower. Ontario s 20 nuclear units produce over 50% of the province s electrical power; hydropower generates another 22%. 2014 ICF International. All rights reserved. 21
The Future for Dawn Storage Marcellus production will tend to hold down the intrinsic value of storage at Dawn as long as production continues to grow. Rapid growth of Marcellus supplies increases winter gas deliverability, thereby holding down winter prices and reducing seasonal price spreads at Dawn. This is likely to continue as long as there are constraints between Dawn and the New England market. However, growth in Ontario power generation gas demand will likely increase the extrinsic value of storage. Gas generators ramp up and down quickly, requiring rapid response from the gas system. But current PPA s and gas supply arrangement with generators do not reflect the need for or benefits of storage. 2014 ICF International. All rights reserved. 22
Thank You! Questions?