TransCanada, Enbridge and Spectra queue up pipeline projects across all of North America
TransCanada adds Canadian capacity
TransCanada Corporation (ticker: TRP) has a new $2.4 billion NGTL system expansion coming on-line within four years. The NGTL moves gas from the North Montney in British Columbia to and through Alberta to Saskatchewan and/or delivery access to the Canadian west coast for export as LNG if such a project becomes a reality.
The company expects the system expansion to be in-service between 2019 and 2021. The expansion includes approximately 375 km (233 miles) of 16-inch to 48-inch pipeline, four compression units and associated facilities.
TransCanada anticipates incremental firm receipt contracts of 620 MMcf/d and firm delivery contracts to major border export and intra-basin delivery locations of 1.0 Bcf/d. With this expansion, NGTL now has a $7.2 billion growth capital program, excluding the $1.9 billion Merrick pipeline project.
TRP NGTL Expansion Project, Feb. 2018
In December 2017, the National Energy Board (NEB) approved the Sundre Crossover Project on the NGTL system. The $100 million project will increase delivery of 229 MMcf/d to the Alberta/British Columbia border to connect with TransCanada downstream pipelines. In-service is planned for April 1, 2018.
NGTL background from Canada’s National Energy Board
NOVA Gas Transmission Ltd. owns the NGTL system natural gas gathering and transportation system in Alberta and northeastern British Columbia. NGTL transports natural gas produced in the Western Canadian Sedimentary Basin to markets in Canada and the United States.
The pipeline commenced operations in 1957 and NGTL came under NEB‑jurisdiction in 2009. NGTL has over 1 100 receipt points and over 300 delivery points. NEB-regulated assets include approximately 24 500 km of pipeline and various auxiliary infrastructure.
In 2016, NGTL delivered over four trillion cubic feet of natural gas which equates to 11 billion cubic feet per day (Bcf/d) or 311 million cubic metres per day. Approximately 40% of deliveries in 2016 were in Alberta and B.C, 19% went to markets in the Pacific Northwest and California, 19% to the Midwestern United States, and 22% to Eastern Canada and the U.S. through various interconnected pipelines.
Key points on NGTL include:
- East Gate – In the southeastern portion of the NGTL system, the East Gate interconnects with TransCanada’s Canadian Mainline (near Empress, Alberta) and TransCanada’s Foothills Pipeline (near McNeill, Alberta).
- West Gate – In the southwestern portion of the NGTL system, the West Gate interconnects with TransCanada’s Foothills Pipeline (British Columbia).
- Upstream of James River – Throughputs in the northwestern portion of the NGTL system. Upstream of James River flows contain receipts from the Horn River and the Groundbirch pipelines (part of NGTL).
- North and East – Throughputs to delivery areas in northern Alberta, including natural gas used for oil sands operations.
Pipelines coming on strong, everywhere
- The $1 billion Northern Courier project commenced transportation services in late January 2018
- The $200 million White Spruce pipeline is expected to receive a decision from the Alberta Energy Regulator in Q1 2018
- Mexico Natural Gas Pipelines – advancing US$2.8 billion capital program with Sur de Texas and Villa de Reyes expected in-service late-2018; Tula expected in-service 2019
- TransCanada’s Gibraltar project (934 MMcf/d) came on-line in November 2017.
- The Rayne Xpress also started transporting natural gas in November, carrying 1 Bcf/d of supply from an interconnect with the Leach XPress pipeline project, and another interconnect, to markets along the system and to the Gulf Coast.
- The Leach XPress was placed in-service January 1, 2018, transporting approximately 1.5 Bcf/d of Marcellus and Utica gas.
The FERC certificate for WB XPress was received in November 2017 and the FERC certificates for Mountaineer Xpress (MXP) and Gulf Xpress (GXP) projects were received on December 29, 2017. The MXP and GXP projects consist of combined infrastructure investments of $3.2 billion. The MXP will deliver approximately 2.6 Bcf/d of gas and the GXP will transport approximately 0.8 Bcf/d to Southeast and Gulf Coast markets.
Keystone XL marching forward
TransCanada is marching forward with the Keystone XL, which received presidential approval in 2017, and approval by Nebraska with a minor change in route. TransCanada is working with local landowners on the Nebraska-mandated route change at this time.
On December 27, 2017, opponents of the Keystone XL project filed an appeal, challenging the November 20, 2017 decision. TransCanada will defend the alternative route approved by the Nebraska Public Service Commission in court. The pipeline recently secured 20-year, 500,000 BOPD contracts, allowing the Keystone XL to proceed.
TransCanada conference call Q&A
Q: At your analyst day you talked about building a potential Permian gas pipeline. Are there any updates on that front, and how do you see the competitive dynamics in the market right now?
EVP and President of US Natural Gas Pipelines Stanley G. Chapman: Big picture-wise, with respect to origination opportunities, I would provide this – our team is working on about CAD$1.5 billion worth of origination projects going forward. Some of these are longer puts, but expect us to compete for and win more than our fair share going forward.
The details to your question are somewhat commercially sensitive right now, so I can’t get into them. But I will tell you this, we are leveraging our existing pipeline network by working closely with Karl and his team in Canada to right outlets for Western Canadian producers to the Northwest into the Midwest.
We’re looking at adding new demand centers to the Mid-Atlantic off of the Columbia gas pipeline and to your question, in particular, we are looking to fill-in some of the white spaces particularly in Texas. We want to be very thoughtful about what we do going forward. We want to remain shrewd to our risk preferences. We are very quietly trying to see if we can put together a project that has long-term contracts with a portfolio of largely investment grade counterparties, returns that work for us.
So, I would ask that you bear with us for a little bit and we will definitely update you as further details mature over the next several months.
Q: This question revolves around deploying capital and two of your major basins in the Marcellus versus the Montney. How do you think about that on a risk-adjusted basis for returns relative to places where you can’t get those contractual terms?
President and CEO Russell Girling: I’ll kickstart and then Karl and Stan can jump in. But I think I gave you our answer to questions from outlook as we believe that these two basins are the lowest cost basin in North America. We’re seeing them both continue to grow as others decline. We don’t know yet how low the price can go, and then still recover full-cycle these returns on investment. But it appears to be something sub-CAD3 and maybe lower as they continue to prove out and get better and better of what they do.
I guess our view is that those two markets, if you think of the North American market being around numbers of 100 billion cubic feet a day and then you add on some export capacity, some increased demand for power, industrial demand, you add that bit of – export to Mexico, people will talk about a market that looks like 120, 130 or more Bcf a day.
There is ample room for them to both to grow. When we’re making our capital investment, first and foremost is the fundamentals. We think fundamentally that they had strong investment to move from the lowest cost basin to market and is going to be fundamentally sound, no matter who owns it, no matter what the term of contract.
And then as we’ve seen, the term of contract in both places has increased. You think of how we build up ANR, for example, first, prior to Columbia with contracts that averaged, if I remember correctly, somewhere in the 23 to 24-year range. GTN, I mean, in that same 20-plus year range. Columbia in that same long-term range. The credit worthiness of these counterparties is improving.
What we saw with small producers, they are still sub-investment grade producers, but they have multibillion-dollar balance sheets today with great positions for future growth. So we kind of combine all those things together. We’re actually not making a choice currently at capital allocation decision between the basins. We think they’re both strong places to invest going forward.
And as we always – as Stan said, we’re very careful about how we contracted and what our paper looks like, but I don’t see the choice. I think they’re both strong fundamentally. The folks who are working with are getting stronger. And as I look at our position going forward, there is going to be ample new opportunities get attached to that. I don’t know, you guys want to add to that, Stan or Karl?
EVP Chapman: This is Stan. I’ll just give you some color commentary with respect to the Appalachian basin and our projects. I think the Appalachia is producing somewhere north of 25 Bcf a day today, growing to 40 Bcf by the end of the next decade and in support of that I would note that we recently, on January 1st, put our Leach Xpress project into service, 1.5 Bcf a day capacity, which today is flowing at just over 1.4 Bcf a day.
So it just goes to show that there is plenty of production out there to fill up expansion projects going forward. That’s an environment where if you look at the forward prices on the NYMEX, it’s hard to find a lot of threes out there. The gas prices on the forward strip are sub-CAD3 for the most part, which is good to the extent that that’s going to track new demand in the form of LNG exports.
So that’s one of the key signpost that we’re going to continue to watch forward. Going forward is the growth in LNG exports, which we believe can get up to that 6, 8, 10 Bcf a day over the next three to five years, so continued growth out of the Marcellus and we’re going to put somewhere around CAD$4.3 billion of new capital investment in service later this year, which is going to be close to 4 Bcf a day capacity and I have every expectation that that’s going to fill up, not unlike our Leach Xpress project did.
EVP and President of Natural Gas Pipelines Karl Johannson: Maybe I’ll just make a comment as well. We talked a lot about when we went up this position in the Marcellus and why the Colombia assets were such a great fit for us. And when I view the work that we got ahead of us and the business that we got ahead of us, I don’t see it is as neither or the capital allocation decision at all. I think, both – we’re sitting on two of the best resources in North America and I think they are very complementary. And as a matter of fact, when we are – when we weren’t together, I always considered their lack of position in the Marcellus and Utica to be a big competitive disadvantage for us.
So when we take a look at what we’ve done, our markets have been impacted by the – WCSB markets have been impacted by Appalachian gas. When we didn’t have a position, we’ve lost some of our US Northeast markets. We’ve seen Rover, we’ve seen NEXUS come into our dawn market, we’ve seen back in the Bakken associated gas decrease the model, WCSB gas it was down the northern border.
So I guess – what I would say is that, we have still lots of work to do and I just don’t see any issue between allocating capital between the two of them. Both of these basins are competitive, and I think that if we’re not working and, one, that gas will still move. So I think we’ve got to be very mindful of that. Just because we choose not to move the gas doesn’t mean it won’t be move and it won’t move in the market that compete with us. So I think we’re quite eager to make sure we maintain our market share in both areas.
Q: Can you talk about the next steps with the NGTL and bringing back some of the mothballed capacity on the Mainline, and if there are any numbers with respect to the capital that might be required here?
EVP Johannson: As you’ve seen, we’ve done about 1 Bcf a day of new delivery capacity to the East Gate. So then the new delivery capacity that we have sold is scheduled to come on about 2020, 2021 timeframe. So we do have a little bit of time.
We have two options to provide people Mainline capacity from that. One, is from existing capacity sitting on the Mainline that is active right now; we do – we are flowing large volumes on the Mainline right now, but we are anticipating some non-renewals on the Mainline. So we are expecting a piece of that – not to come from the existing capacity that we have right now.
The rest of it will come from us – from us reactivating capacity that right now is, so to speak dormant the capacities in there, but that isn’t ready to be used. That’s relatively cheap capacity to bring back, it generally just requires some maintenance or acquire some compressor work, some maintenance and some integrity work. So that is relatively – I don’t have number right now, so I don’t know the exact amount that we can bring back, but it is relatively cheap as well as maintenance.
They can come back relatively quickly and we have probably in total about 1.5 billion cubic feet a day, maybe slightly more of that capacity available on the Mainline. So we should be able to take care of between that and the existing nominal as we’re expecting over the next couple years. We should be able to take care about all the 1 billion cubic feet a day of new delivery capacity quite easily.
Enbridge brings ~$12 billion on-line in 2017
Enbridge Energy Partners, L.P. (ticker: EEP) had a variety of projects power on in 2017. The Sabal Trail (USD$1.6 billion), Bakken Pipeline (USD$1.5 billion) and the Regional Oil Sands Optimization projects at Athabasca Twin (CAD$1.3 billion) and Wood Buffalo (CAD$1.3 billion) were the most capital-intensive projects Enbridge had in 2017.
EEP Projects Brought into Service in 2017, Feb. 2018
2018-20 schedule released
EEP’s biggest 2018 project, the USD$1.5 billion Valley Crossing Pipeline, is expected to be in-service in Q4 2018. According to the most recent investor presentation, the pipeline is 80% complete.
The NEXUS project (USD$1.3 billion) should be in-service in Q3 2018. The pipeline is 25% complete in Michigan, according to EEP.
EEP 2018-20 Project Schedule, Feb. 2018
Line 3 Replacement – moving forward
The Line 3 Replacement is scheduled for 2H 2019, and as of February 2018, costs are projected to run CAD$5.3 billion for Canada’s portion and USD$2.9 billion for America’s portion. EEP said that the 2017 Canadian construction program was completed on-time and on-budget, with 400 km laid. Construction in Wisconsin is complete and Minnesota is moving forward with its regulatory processes.
EEP Line 3 Replacement Project Update, Feb. 2018
Spectra Energy builds bridges
Spectra Energy Partners, LP (ticker: SEP) will contribute approximately $1.3 billion to the aforementioned NEXUS pipeline, whereas the PennEast pipeline will be allotted $260 million from Spectra.
The Atlantic Bridge project runs along the East Coast, with a CapEx of $500 million. The project entered partial service in November 2017 and full service is expected in Q4 2018. Approximately 135 MMcf/d of capacity will be added to the Algonquin, Maritimes and Northeast pipelines.
SEP Atlantic Bridge, Feb. 2018
Spectra increases upstream capacity, connecting Marcellus and Utica supply to NEXUS and OPEN
The Texas Eastern Appalachian Lease (TEAL) will add 950 MMcf/d of capacity to the area, looping 4.5 miles on the Texas Eastern mainline, connecting OPEN and NEXUS. Spectra plans to spend $200 million on TEAL. According to Spectra, TEAL is expected to be in-service Q3 2018.
SEP TEAL, Feb. 2018
