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Canada: Stuck Between a Rock and a Hard Place, Part 2

June 25, 2015 | By Warren Waite

Canada is the world’s fifth largest producer of natural gas, accounting for 5% of global production according to Canada’s National Energy Board (NEB). Our friends to the north also produce more natural gas than it can consume domestically and ever since the shale revolution’s inception in 2008, net exports to the U.S. have been on a downturn. The beauty of efficient energy markets is that what goes in (production from underground natural resources) must come out (consumed for residential, commercial, industrial use, exported to the U.S. or through the utilization of storage).

In this edition of Get the Point, we’ll dive into the dynamics of U.S. and Canada border flows and more importantly, look at the different forms of gas consumption within Canada along with a high level overview of proposed LNG export projects -- none of which will likely be in service until after 2020. There are many other market fundamentals to consider such as the interplay of NGL and crude fundamentals within Canada. However, those elements fall outside the scope of today’s posting.  We’ll utilize a variety of data sources to best frame what the potential is for Canadian natural gas production and demand in the years to come.

In part 1, we discussed and put into perspective Canadian natural gas production, the fallout from the plunge in oil prices and the resiliency of producers in a low hydrocarbon price environment. Despite the current leveling of production in the U.S. as discussed last week in Gas Production in the U.S. at a Standstill?, U.S. production  is still expected to grow in the coming years to meet a surge of future demand-- namely liquefied natural gas (LNG) exports.  With that being said, gas exports from Canada to the U.S. will bear the brunt of the displacement effect from growing supplies within the lower 48, with regional export flows increasing in some areas and declining in others.

Use it or lose it

After years of decline, Canadian dry gas production rounded the corner in 2013, adding 0.1 Bcf/d, and another 0.6 Bcf/d to average 14.2 Bcf/d in 2014. So far this year, production is averaging 15.1 Bcf/d, similar to production levels in late-2008. Where does all that gas go? Back in 2005 about 9.2 Bcf/d, or 56%, of domestic supplies in Canada were exported to the U.S. from border crossings that span from Washington to Maine. According to Statistics Canada, total gas consumed averaged 7.6 Bcf/d in 2005, or 46% of total production. By 2014, net exports plummeted 3.6 Bcf/d to average just 40% of production and total gas consumed hit 8.6 Bcf/d or 61% of production volumes.  Injections into storage or withdrawals from storage account for any imbalances that may exist. Later in this posting we’ll chronicle the main drivers of this gas demand growth; oil sands and electric power. 

2014 Wellhead Production Growth by Region

Exports to the Northeast

It is evident in the chart below the impacts of the Marcellus and Utica Shale have had on Canadian exports to the U.S., particularly the Northeast. In 2009, Canada delivered 1.9 Bcf/d to the Northeast by way of Niagara Falls, Ontario,  Iroquois Ontario, St. Stephen, New Brunswick and a handful of smaller inter and intra-state pipelines along the St. Lawrence waterway. By 2014, exports to the Northeast fell 83% to average a paltry 0.3 Bcf/d. As shown in the graph below, during the summer of 2013 that relationship flipped the other way due to the cyclical nature of Northeast demand and growing Northeast production. As future Northeast infrastructure projects come online, it’s likely that the Northeast will be an annual net exporter of gas to Canada by 2017. Per, PointLogic Energy’s Infrastructure Informant, U.S. exports are set to grow via Tennessee’s Niagara Expansion Project which will provide an incremental 158 MMcf/d beginning this winter.  In late-2016 Iroquois Gas Transmission will expand several interconnects and increase its ability to send gas north allowing up to 300 MMcf/d of gas to be exported to East Canada. 

Ohio Wellhead Production by County

Exports to the Midcontinent

PointLogic Energy’s Infrastructure Informant is tracking nearly 3.0 Bcf/d of projects in 2015 alone that will bring gas from the Marcellus and Utica Shale to states in the Midwest. Through 2017 there is an incremental 9.8 Bcf/d of planned projects that all target the Midwest. The lower cost supply originating from the Marcellus and Utica will be the preferred source over Canadian exports, but there are still a few import and export points that will maintain an important role in the future interplay of border flows through the Midwest. 

As Canadian exports compete for Midwest market share, net exports to the Midwest have oscillated between 2.2 Bcf/d to 2.6 Bcf/d. Historically, Canadian gas was delivered into Michigan to refill storage and to serve load around the Chicago Hub, but less and less of that is happening due to the aforementioned displacement effects.

Canadian exports at Monchy, Saskatchewan to Port of Morgan, Montana peaked at an annual average of 2.0 Bcf/d in 2012, but as associated gas production growth occurred in the Bakken Shale, those volumes fell 28% to average 1.5 Bcf/d in 2014 and continue to hover at that level today. Another export point that has declined is at the interconnects at Emerson, Manitoba where gas flows have been cut in half from 1.9 Bcf/d in 2009 to around 0.9 Bcf/d last year. On occasion, depending on operational constraints in eastern Canada, Emerson will net deliver gas back into Canada. 

The only Midwest border point that has actually increased is at Carnduff, Saskatchewan where Alliance pipeline transports wet gas (a raw mix of unprocessed methane and NGLs) destined for the Aux Sable, Illinois processing plant.  Throughput on Alliance averaged 1.6 Bcf/d of its 2.0 Bcf/d capacity back in 2009. Over the last few years, as production growth occurred in Alberta, an incremental 0.3 Bcf/d was moved through the pipe yielding 96% utilization last year and has been essentially full this year running at 99% utilization. 

Ontario also receives gas from Michigan at a handful of border points, but in large part those exist at Sarnia, Ontario or on the U.S. side at St. Clair, Michigan. With smaller amounts of gas leaving Eastern Canada to the Northeast, so too is the need for gas to flow into southeastern Ontario through the Dawn Hub. Ontario imports from Michigan have fallen 1.0 Bcf/d since 2009 to average 1.5 Bcf/d in 2014.  Year-to-date, gas leaving St. Clair, Michigan has averaged 1.4 Bcf/d.  Looking forward, the prospect of increased throughput at St. Clair is strong. Pipeline projects such as Energy Transfer’s Rover Pipeline, Spectra’s Nexus Transmission, Union Gas pipeline’s Dawn to Parkway expansions and TransCanada’s Eastern Mainline Project all coupled together will elevate the amount of gas leaving Michigan.  Ultimately, this is another route for Marcellus and Utica supplies to reach new markets in Sarnia, Toronto and Montreal therefore, displacing gas flows from west-to-east Canada across the TransCanada Mainline. Given these dynamics, it is probable that by the early 2020’s Canada could be a net importer of gas from the U.S.

Exports to the Pacific Northwest

As Canadian exports feel the ripple effect from east-to-west displacement pressure, the last remaining export market left to defend is the Pacific Northwest. Here, production from British Columbia and Alberta can remain competitive with supplies from the Rockies for downstream market share in the Pacific Northwest and into California. In the case of Westcoast Pipeline, production from the Montney formation is limited in its ability to traverse east into growing Alberta markets. This leads to what is basically captive and discounted supply to export into the U.S. at the border of Huntingdon, BC and Sumas, Washington. The other border point is with TransCanada Foothills (TC-Foothills) pipeline and Gas Transmission Northwest (GTN) at Kingsgate, BC and Eastport, Idaho. Receipts on TC-Foothills originate from a myriad of pipeline assets in Alberta that filter gas into British Columbia. 

Coupled with the westward push of displacement pressure, demand in the Pacific Northwest has increased due to gains in gas-fired generation in the wake of a severe and multi-year drought along the west coast. PointLogic Energy sample data utilizing our new Excel add-in tool highlights this fact. 

Ohio Rig County by County

Year-to-date deliveries to power plants in Idaho, Oregon and Washington are 0.1 Bcf/d above their three-year average over the same period. Likewise GTN deliveries of Canadian gas to Malin, Oregon have increased 0.2 Bcf/d YTD compared to the prior three-year average of 1 Bcf/d. In all, Canadian exports to the Pacific Northwest stand at 3 Bcf/d in 2015, a gain of 0.5 Bcf/d from the prior three-year average and over 1 Bcf/d from 2009 levels. 

As westward displacement pressure grows there are limits to how much gas can move south of the U.S. and Canadian border. Barring any expansion projects, throughput at TC-Foothills Kingsgate international interconnect with GTN over the past 12 months have averaged 79% utilization, but have peaked at over 95% of capacity on numerous days in the last year. Northwest Pipeline receipts at Sumas, Washington stand at 65% utilization over the past 12 months, peaking over 95% of capacity on a handful of occasions. In total there is roughly 0.8 Bcf/d on average of available capacity to the Pacific Northwest, yet on those restricted days it could be less than 0.2 Bcf/d.

Effects on prices

The AECO-C Hub is the nexus of a system of pipeline and storage assets in Alberta that has traditionally been the least expensive location in North America to purchase natural gas. This is due to the need to discount prices in order to capture the cost of transport to distant markets in the U.S.

PointLogic Energy Excel Add-in

Prices at AECO have averaged near CAD $2.50/Gigajoule (GJ) for the last five months and are expected to remain in that area for the remainder of the summer. Note that AECO prices are roughly a dollar below the five-year average mark in some months. During periods of weak demand, AECO’s discount to Henry Hub can reach between $1 and $2/GJ.

Ohio Supply Related Pipeline Flows by County

The forward outlook for AECO prices mirrors that of Henry Hub’s contango forward curve. Prices are expected to increase over the long-run due to systemic demand growth across North America. This is good news for producers, but production levels can’t exceed the balancing act of displacing exports to the U.S., growing domestic gas consumption and LNG exports -- if any of those projects come to fruition. In the meantime, Canada is stuck between a rock and a hard place.

Ohio Average Daily Wellhead Production 2014

Industrial Demand Opportunities

Close to 60% of domestic demand in Canada is based in Western Canada, which happens to be where the largest driver for demand growth is occurring. Canadian demand growth is driven by industrial demand which is heavily weighted to the oil sands, where natural gas is used for the in-situ process of extracting bitumen, and from gas-fired power generation in Alberta and Ontario. 

According to Canada’s National Energy Board, in-situ oil sands production is expected to be one of Canada’s largest sources of future oil growth. Despite the drop in crude prices several of the long-term capital intensive expansion projects are still slated to move forward. The in-situ process (click here for a video explanation) can be very energy-intensive and consumes a lot of natural gas. 

West Virginia Production by County

The most recent forecast by the Alberta Energy Regulator (AER) states natural gas use that is purchased or processed locally on site for in-situ recovery or for mining and upgrading will surpass 5.0 Bcf/d by 2021. That is a gain of nearly 2.3 Bcf/d from 2013 levels. AER’s ST98-2015 report should be released sometime this summer and will likely have a lower forecast for gas use in the oil sands given that some long-term oil sands expansions plans that have yet to start construction or reach final investment decision (FID), are on hold or canceled altogether. Additionally, in-situ producers have become more efficient, and through technological innovations, have lowered their steam oil ratio (SOR). This is a ratio of the volume of steam-- heated by natural gas-- required to produce one unit of oil.  According to AER data, All Thermal In-Situ’s SOR decreased from 3.13 in 2013 to 2.89 in early 2015. Likewise, Steam Assisted Gravity Drainage (SAGD) decreased from 2.91 in 2013 to 2.6 in the first two months of 2015. Hence, there is plenty of downside risk to last year’s gas use forecast.

A categorical breakout of the total gas consumed within Canada as depicted earlier in this posting can be found below.  Industrial demand has grown 29% since 2007 led by the surge in gas demand for the oil sands. In fact, if you align the AER data with Statistics Canada, in 2013 about half of all the industrial gas demand can be attributed to the oil sands.  In 2007, gas use in the oil sands was 38% of the industrial demand. 

West Virginia Rig Count by County

The population of Canada is estimated to have grown by 2.2 million from 2007 to reach 35.3 million in 2014. The current annual population growth rate is 1.2 % with the majority of people living in densely populated areas such as Toronto, Montreal, Vancouver and Calgary. Ignoring the nuances of below-normal winter weather, over time residential use of natural gas will continue to increase. However, that growth is quite small compared to the future expectations for the industrial sector.

Similar to environmental regulations in the U.S., Canadian regulations on the national and provincial level have deterred the use of coal-fired power generation. As of 2014, Ontario retired its last remaining coal plant. In May, the Canadian government announced plans to reduce its greenhouse gas (GHG) emissions by 30% below 2005 levels by 2030. A portion of the regulatory measures will impact GHG methane emissions in the oil and gas sector, natural gas fired electricity generations as well as the petrochemical industry. 

The impacts of environmental regulations aren’t as severe to the generation mix in Canada as it is in the U.S. Canada is one of the world’s largest producers of hydroelectricity and provided 57% of its generation mix in 2012. Canada’s National Energy Board projects hydro to fall to 52% and natural gas to increase from 15% in 2012 to 22% of the generation stack by 2035. Declines in the use of coal and gains from renewable energy are also noteworthy as shown in the graph below.

West Virginia Related Pipeline Flows by County

Supporting greater use of natural gas to generate electricity in Canada are low gas prices, lower GHG emissions compared to coal-fired plants, well-developed infrastructure, smaller upfront capital cost and shorter construction times than their coal and nuclear counterparts. The NEB projects gas-fired generation to more than double over their projection period, rising from 68 terawatt hours (TWh) in 2012 to 164 TWh in 2035. In terms of gas consumption, that equates to a 1.8 Bcf/d increase. The majority of that increase is in Alberta, growing an incremental 1.0 Bcf/d followed by 0.2 Bcf/d increases in Saskatchewan, Ontario, British Columbia and a 0.1 Bcf/d uptick in Quebec. Alberta will account for 66% of the total incremental industrial and power generation gas demand in Canada between 2013 and 2035, according to NEB data.

The Alberta Electric System Operator (AESO) in their 2014 Long-term Outlook took into account their evolving generation mix and growing power needs of the province. Based upon their analysis and several scenario forecasts, gas demand from gas-fired generation for combined cycle, simple cycle and cogeneration plants could increase almost 0.6 Bcf/d from 2013 to 2019 in their Main Outlook scenario. In the Low Growth scenario, gas demand would only increase by 0.2 Bcf/d.  

Compared to the NEB, the AESO forecast shows greater potential for gas demand. However, the two forecasts were completed in different years and consequently have different data sets, assumptions and forecast horizons. By 2034, AESO forecasts gas-fired generation to increase 0.6–1.3 Bcf/d. The average of that range falls in line with the 1.0 Bcf/d of growth by 2035 in the NEB forecast.

West Virginia Daily Wellhead Production 2014

LNG, the golden Canadian goose

A once promising outlet for excess natural gas in Canada, the prospect for LNG exports has deteriorated amid market conditions, lack of progress from LNG developers and bureaucratic issues. Over the years, many market participants have touted building an LNG export terminal off the coast of B.C. or in some cases Atlantic Canada. However, in a globally competitive race with finite world demand for LNG and stiff competition from countries like the Australia, the U.S. and nations in the Middle East and West Africa and others, Canada is at a disadvantage. Like Canada, the overwhelming majority of the competing LNG export projects target the Asia-Pacific Basin to quench the growing needs of countries like Japan, South Korea, China and India. Pipeline delivered gas from Russia to China is also a threat. 

To export LNG from Canada a permit from the NEB is required in addition to both federal and provincial environmental assessments and permits, as well as approval from First Nations. Nearly all of the proposed LNG export terminal projects in Canada are new builds (greenfield) requiring billions of dollars in capital investment to build the liquefaction terminals, on-site storage, docks for the LNG vessels plus the build-out of gas pipelines to bring distant supply to the coast. 

PointLogic Energy’s Infrastructure Informant –LNG is tracking 26 projects across Canada with those receiving NEB approval totaling 11 plus another 13 whose application is pending and two announced projects that have yet to file.  Five projects totaling over 4 Bcf/d are in East Canada while an astonishing 32 Bcf/d of export capacity is proposed in West Canada, spread over 21 proposed projects. According to research from Frost & Sullivan, the global LNG market had 32.42 Bcf/d of supply in 2014 and is forecast to reach 69.26 Bcf/d in 2025. By 2025, Asia is projected to nearly double its current demand to 23 Bcf/d. Market consensus is that about one to three Canadian LNG projects will come to fruition during the 2020’s. Therefore, pinning hopes and dreams of LNG as a major demand outlet during the current decade would be ambitious to say the least. 

According to the International Energy Agency’s (IEA) Medium-Term Report 2015, almost 22 Bcf/d of incremental LNG export capacity will be added by 2020, or 40% more than current levels. By 2020, the IEA forecasts ranks Australia as the world’s largest exporter of LNG followed by Qatar and the U.S. In the report, no Canadian LNG export projects made the cut for their forecast ending in the year 2020. They cite the high upfront costs of greenfield projects and the need for expensive upstream infrastructure, challenges in securing skilled labor and taxation issues. In early 2014, the B.C. government proposed a heavily criticized provincial LNG taxation plan and by the end of year eased the tax burden on the industry. To date, there are no final investment decisions (FIDs) for Canadian LNG projects despite the B.C. government passing further investment-friendly policies amid the oil price collapse.

Pacific Northwest LNG announced on June 12 that it had reached a conditional FID. The conditions for the company are approval of the Project Development Agreement by the Legislature and regulatory approval from the Canadian Environmental Assessment Agency. If all goes well and a final FID is obtained it would still take approximately four years to construct with commercial operations targeted to begin in 2019, according to Pacific Northwest LNG. Until, a final FID is given it is likely that this project will remain post 2020 in many LNG prognosticators’ forecast. 

LNG buyers have gained an advantage in the global LNG race in terms of how they contract for LNG. Historically, LNG was purchased under 20+ year contracts that were linked to the price of crude and limited their ability to resell cargoes as needs or market conditions changed. In today’s world, buyers have choice. They can buy LNG linked to oil, or natural gas prices at Henry Hub, Louisiana or European based gas prices. Contracts are becoming shorter in tenure and barriers of what buyers can do with that LNG are being removed. For years, the proposed Canadian LNG projects were oil linked, but what developers are doing today to entice off take commitments remains to be seen. The pricing scheme is only one of many challenges LNG developers face in Canada, despite the shorter distance and lower shipping cost to reach the Asia-Pacific. 

In a May 2015 presentation, the Canadian Energy Research Institute (CERI) provided their view on the future role of Canadian LNG exports. By 2022, CERI projects two B.C. LNG projects of up to 3.2 Bcf/d. Though they differ in opinion from the IEA on Canada’s LNG volume prior to 2020, it is clear that over the next four to five years, the golden Canadian goose (LNG) is cooked and Canada will remain a price taker based on market dynamics taking place in the U.S.

Pennsylvania Supply Flows by Region

According to an analysis by CERI, the minimum price needed to make B.C. LNG projects viable is $12/Mcf. This takes into account field supply costs, pipeline transportation tolls, liquefaction cost, loading and shipping costs and regasification costs to reach Tokyo, Japan. In May, Asian LNG prices fell below $7/MMBtu. 

Short-term Supply and Price Outlook

Last week, the NEB released its Short-term Candian Natural Gas Deliverability 2015-2017 – Energy Market Assessment. This report highlights many of the challenges facing Canada as North America remains over supplied from 2015-2017. The report is a nice supplement to the issues raised in part one and two of this Get the Point series. The NEB study provides three scenarios of future gas prices and how the deliverability of Canadian production would change. By 2017, total Canadian deliverability could vary by 1.7 Bcf/d depending on the pricing scenario and market conditions.

Pennsylvania Supply Flows by Region

In the low price case, Western Canadian gas faces stiffer competition from U.S. and gets squeezed out of market share to the Eastern U.S. and central Canada. Henry Hub prices average $2.70/MMBtu in 2015 and Canadian gas production averages 14.6 Bcf/d or a 0.1 Bcf/d decrease from 2014 levels.  Henry Hub cash prices rise to $3.10/MMBtu in 2017, but deliverability declines 0.8 Bcf/d from 2014 levels to average 13.9 Bcf/d.

In the Mid-Range price case, the market remains oversupplied and production is relatively flat in 2015 and declining in 2016. By 2017, increased North American demand tightens the market enough where prices encourage enough drilling to maintain steady deliverability. Henry Hub prices recover from the $2.90/MMBtu lows set in 2015 to reach $3.55/MMBtu in 2017, yet production in 2017 is flat to 2014 levels. 

The Higher-Price case assumes a tighter market from rising demand, less displacement of exports to the U.S. and producer access to capital eases where continued focus on drilling efforts on highly productive prospects is conducive enough to increase deliverability. Henry Hub prices reach $3.70/MMBtu in 2017 and Canadian deliverability climbs 0.9 Bcf/d from 2014 levels to average 15.6 Bcf/d in 2017. 

Final Thoughts

Canadian natural gas production will continue to face a slew of headwinds over the next several years. As discussed above and according to NEB assessments, production output by 2017 could range as low as 13.9 Bcf/d or as high as 15.6 Bcf/d. Assuming the higher price scenario plays out, that would equate to approximately 0.9 Bcf/d of incremental demand by way of gas use in the oil sands, gas-fired generation, residential and commercial use and exports to the lower 48. Are domestic demand opportunities enough to absorb the incremental supplies or will exports need to increase? Since the lion’s share of Canadian production is in Alberta and the growth spot for oil sands demand and future power generation, a closer look at the fundamentals in Alberta is needed.

The AER forecast for oil sands demand states that by 2017 gas demand could increase by 1.2 Bcf/d. The AESO forecast for gas-fired generation growth in Alberta yields 0.2-0.6 Bcf/d of new gas demand by 2019. Export opportunities to the eastern and central U.S. are dwindling and options to move gas to the Pacific Northwest could range from 0.2-0.8 Bcf/d depending on the gas day. Therefore, it appears the potential for incremental domestic demand to consume any increased gas production in Alberta is evident. However, as domestic demand grows and prices at AECO become less dependent on market fundamentals in the lower 48, Alberta prices will still need to fiercely compete with the markets in the Western U.S. Regardless, until the 2020’s arrive, Canada will remain a market in transition and a country that is stuck between a rock and a hard place. 

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