Pipeline 20180704

PIPELINE NEWS SASKATCHEWAN’S PETROLEUM MONTHLY Canada Post Publication No. 40069240

www.pipelinenews.ca

July 2018

Vol. 11/2

Bakken Now: Williston Basin Petroleum Conference 2018

North Dakota is firing on all cylinders, with a new record of 1.2 million barrels per day of oil production, on a trend towards 1.6 million and possibly 2 million barrels per day. This is the recently-purchased Marathon Dickinson Refinery. It opened just as the downturn hit, and struggled in those years. But things have picked up enough that a new refinery, the Davis Refinery, has just been given the green light to be built about 27 kilometres west of this site. Photo by Brian Zinchuk

Ceres re-examining crude-by-rail at Northgate A6 & 7

Raging River and Baytex merge

A3, 7 & 8

Davis Refinery approved in North Dakota A9 & 10

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PIPELINE NEWS July 2018

Ceres is getting serious about crude-by-rail out of Northgate

Right now, Ceres Global Ag is shipping propane out of its Northgate Terminal. They are strongly considering revisiting the idea of crude-by-rail for the facility.

Photo by Brian Zinchuk

By Brian Zinchuk Regina, Northgate – When the Ceres Northgate Terminal, previously called the Ceres Northgate Commodity Hub, was first initiated, crude-by-rail was a big part of the plans. But just as the facility was coming online, the oil crash put the kybosh on building out the crude-by-rail portion.

However, with oil prices having recovered somewhat, Ceres Global Ag Corp. is seriously looking at reviving those crude-by-rail ideas, and several different options to expand their facility that could even mean reviving an old, abandoned rail line or building a pipeline to Stoughton.

Robert Day, Ceres’ president and CEO, sat down with Pipeline News in Regina on June 7 to discuss these plans in depth. He had just met with Trade and Export Development Minister Jeremy Harrison.

Oil and gas was a big part of the initial plans for Northgate, but that was before his time with the company. Day said, “At the time, oil was US$110 a barrel. There was less infrastructure than there is today. That was a big part of that initial plan. I believe Ceres had to go through a fund-raising phase to fully develop the site. At the time oil would have been an opportunity, they didn’t have all the funds needed to develop it for that. They were able to put a rights offering together pretty quickly and they raised capital needed to develop the site. By the time they raised that capital, oil had begun its plummet, and it no longer made sense to develop the infrastructure for that project. Instead they focused on the grain elevator and the other things that we’ve done so far.”

There was enough economics behind the project to go ahead without oil.

The site has two loop tracks and several ladder tracks. It started with a grain transloading system, now has a large concrete and steel grain terminal, a 26,000ton fertilizer warehouse, and liquified petroleum gas (propane) transloading facilities. They have handled chemicals in totes and magnesium chloride, as well as quite a bit of fertilizer.

They’ve just started bringing in oil country tubular goods. Frac sand is a possibility for the future.

The 1,200-acre site has ample room from expansion, and Ceres is looking at a specialty grain facility in short order. They’re looking at a possible canola crushing facility on the east side with a partner, a project that would be around US$200 million.

On the west side, there’s an area that could be developed for crude-by-rail, including eventually substantial tankage and loading racks.

Ceres operates three grain facilities in the Minneapolis rail switching district, including Savage, on the Mississippi river, with four bins each the size of a Panamax vessel. “One bin is about 70 per cent of the entire Northgate storage capacity,” he said. It is also capable of loading barges onto the Minnesota (and therefore Mississippi) river system.

Malt One is in Minneapolis and Shakopee is south of the city.

At Duluth, they have a grain terminal at the very tip of Lake Superior, capable of loading oceangoing and Laker ships. Duluth is four times the size of Northgate, and a former Cargill facility.

They also have a grain facility in Port Colborne, Ont. While they have these numerous facilities, the

investment and business out of Northgate is equal to the rest combined.

“At our core, we’re a grain and oilseed merchandizing company that is focused on being a key ingredient supplier to qualityconscious customers. But some of our locations, and really Northgate, in particular, allow us to play a role as a supply chain service provider across a wide range of commodities and finished products,” Day said.

Northgate advantage Speaking about the logistics cost advantage at Northgate, Day said, “We can originate Canadian products directly onto a U.S. railroad, the BNSF, that gives us direct access to U.S. destinations, BNSF destinations, and U.S. export gateways, at a lower cost than other Canadian companies that are trying to reach those destinations by rail. So that is the advantage. If it’s purely a cost play, and a Canadian product that’s going to go to a U.S. destination, and it’s a BNSF destination, we’re more competitive. Whatever the Canadian railroad charges, we don’t have that cost.”

He noted the BNSF’s service performance and reliability, having recently invested over US$20 billion in its infrastructure over the past five years. This is of particular note as earlier in 2018 Canadian railways were struggling to meet demand, especially for grain and potash.

“Canada hasn’t figured out how to create a system that allows the railroads to sufficiently reinvest into their infrastructure. It causes them to be less consistent than a company like the BNSF,” Day said.

Destinations Asked where current product from Northgate goes, Day said, “We have product going out to the

U.S. Pacific Northwest that’s primarily going to Japan. We have product that’s going to Duluth, and that’s primarily going into Europe, Southern and Northern Europe, by ocean-going vessel. We’re also sending some volume out through the Texas gulf that is going to Africa, and we’re sending shuttle trains directly to Mexico, for processing in Mexico.”

“There are a host of U.S. destinations products are going to.”

The key petroleum product they are shipping is locally-produced propane from Saskatchewan gas plants for the last 2.5 years, primarily from Stoughton.

It’s loaded at Northgate and heads south. “A lot of it is going to Mexico,” he said.

“And a lot is going to the United States.”

He noted they are having a lot of discussions with various companies about moving dry bulk and packaged commodities, product lines they expect to get started in six to 12 months.

Stewart Southern Rail Ceres is a 25 per cent owner in the Stewart Southern Railway (SSR), a short line that runs from Stoughton to Richardson, just outside Regina. It had been quite busy shipping crude-by-rail from Crescent Point’s loading facility at Stoughton. That was initially done with trucks to rail transloading, but later upgraded to a loading manifold and a pipeline from Crescent Point’s Viewfield facility. The crude-by-rail is at a standstill on the SSR right now, but there is ongoing substantial development of agricultural users along the line.

There is no rail connection between Stoughton and Northgate, nor has there ever been. There once was a CN line that ran from Northgate to Frobisher,

Steelman and Lampman, but no connection between Lampman and Stoughton.

That rail has long since been abandoned and removed, all except for a very short piece CN has kept at the border – such that Ceres had to move their rail a bit to the east when they built.

The point remains that that right-of-way, and most of the railbed, still exists.

Asked about this, Day said, “The early thinking on this was it could potentially connect. I think the people that originally invested in that, wanted to own 100 per cent of it. For whatever reason, they arrived at 25 per cent ownership. It was viewed as a strategic investment to potentially connect to Northgate.”

“The challenge is, it’s really expensive. In theory, it’s easy, because the railbed is there. But you have to acquire that.”

“The thing that’s prevented us from seriously pursuing it is our high-level estimates on the cost to connect it are very expensive - US$150 million,” Day said.

“If the cost was US$50 million, I think it’s probably a no brainer. Between $50 and $150 million, its still not out of the question. The big challenge is you need all the major volume opportunities to come together at once and be committed to this. If they all could, then I think it potentially works.

But getting all those things to be happen at once is a challenge.

“You need the oil volume, you need the potash volume, you need the grain volume. If you have all three of those things, you have in the neighbourhood of two million metric tonnes per year.”

Crude-by-rail Day spoke about BNSF “shuttle trains,” also known as unit trains. They

are one-origin, one destination, 100 or 120 cars long. There are incentives offered by the railroad for loading times under 10 hours or under 15 hours. The DET program allows you to break up 110 to 120 car trains with one origin, but “you can explode the train into no less than 25-car units than go in other directions,” he said.

“The DET program works really well for us at Northgate, because we handle so many different products. Most elevators in both Canada and the United States will focus on two or maybe three products. Shuttle freight works okay because you don’t have a mix of products. We’re handling four to five products consistently through the elevator. For us to handle four or five products through one train, and have a financial benefit for the volume we’re loading, is a real advantage.”

The initial plan was the outer loop would be used for oil, principally unit trains. It’s currently being used for propane.

“We’re loading a lot of propane cars. The outer loop is very active,” he said.

Crude-by-rail died off in a big way before they had the opportunity to implement it. But what is the price threshold for it to come back?

“I can tell you where those thresholds are today. Really, it’s more about spreads of different qualities than threshold, but at the same time, the higher the price, the wider the spreads typically are, so there is a correlation there. And then the opportunity with heavy is very different than the opportunity with ► Page A6

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PIPELINE NEWS July 2018

A3

Raging River Exploration to merge with Baytex Energy

By Brian Zinchuk Calgary – Baytex Energy Corp., long a prominent player in the heavy oil region near Maidstone, has scooped up Raging River Exploration Inc., a prominent player in the Viking play near Kindersley, in a $2.8 billion all-stock deal, announced on June 18.

The combination creates a company with a $5 billion enterprise value, and five major core areas, two of which, the Viking and Lloydminster areas, are in Saskatchewan. Its combined production is expected to be over 100,000 boepd in 2019.

The transaction will result in holders of common shares of Raging River receiving, directly or indirectly, 1.36 common shares of Baytex for each Raging River share owned. The exchange ratio was determined based on the market trading levels of the Baytex shares and Raging River shares at the time the companies entered into exclusive negotiations. The board of directors of Baytex and the board of directors of Raging River have unanimously approved the transaction and have received fairness opinions from their respec-

tive financial advisors.

The transaction is subject to approval by the shareholders of both companies, the Court of Queen’s Bench of Alberta and certain regulatory and other authorities, and is subject to the satisfaction or waiver of other customary closing conditions. The transaction is anticipated to close in August 2018.

Neil Roszell, executive chairman and chief executive officer of Raging River, will serve as chairman and Edward LaFehr, president and chief executive officer of Baytex, will serve as president and CEO of the combined company. The balance of the senior management of the combined company will incorporate senior individuals from both Baytex and Raging River.

The board of directors of the combined company will consist of members of both the Baytex Board and the Raging River Board with Raymond Chan serving as lead independent director.

In a press release, Roszell said, “We are uniting two strong oil companies with exceptional people and assets. This combination creates a diversified, well-capitalized oil producer

that has an impressive suite of high quality producing assets and the ability to materially advance our East Duvernay Shale light oil opportunity, while continuing to develop our Eagle Ford, Viking, Peace River and Lloydminster core assets. The combination provides a substantial value proposition for all shareholders of Raging River and Baytex incremental to what each company could deliver on its own. The combination with Baytex is an excellent outcome to the comprehensive strategic process undertaken by the Raging River Board.”

LaFehr said, “We believe the combined company will deliver a powerful combination of industryleading returns, attractive production growth and strong free cash flow generation. The merger creates a company with world class assets and a strong balance sheet while retaining substantial torque to higher crude oil prices. We will be well-positioned to optimize our capital investment program across our high rate of return asset base. The combined company has a dominant 260,000 net acre position in the emerging

Baytex Energy Corp. has long been active in the Soda Lake area, south of Maidstone, as seen here in February 2017. File photo East Duvernay Shale oil play which has the potential to compete for capital with the best plays in North America.”

“I’m really excited to unleash this new, powerful combination of assets and people, that share a highly aligned strategy, and culture of operational excellence and innovation.

Our vision is to build this top-tier North American oil company through disciplined growth and returns to shareholders. The new

company will be a selffunded business model, focused on per share growth, targeting a 10 to 15 per cent total return to shareholders, while driving our net debt to adjusted funds flow ratio down to 1.5 times,” LaFehr said.

He promised accelerating activity, particularly in the East Duvernay, and accretive acquisitions, and mitigating its decline rate to less than 30 per cent over time.

Roszell said in the con-

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ference call, “This is a truly compelling combination that creates an even stronger company. It’s better positioned for value creation, well beyond what either of our companies could do on a stand-alone basis.”

A day after the announcement, Raging River had five rigs working in the Viking play near Kindersley, and one in the East Duvernay play near Pembina.

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PIPELINE NEWS July 2018

PIPELINE NEWS

EDITORIAL

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In North Dakota, it’s full steam ahead. Here, not so much The Williston Basin Petroleum Conference alternates between Regina and Bismarck, N.D., each year. This year it was held in Bismarck. We’ve always found it to be a good barometer of moods and attitudes in the oilpatch, especially with regards to the North Dakota version. There, you really get the vibes over the three days of the show. In Canada, it’s a little more subdued, which may be in keeping with our nature.

This year, a week after the Williston Basin Conference, was the Redvers & District Oil Showcase, thus providing a good contrast between Saskatchewan and North Dakota.

In North Dakota, they are going great guns. Everyone is starting to act like it’s 2010 again. The boom is firing up again.

They are looking for 6,000 people this year, 5,000 next year, and 10,000 the following year.

In 2021, the state’s rig count is expected to be roughly double the 65 it is now. That won’t put it in the halcyon days of 186 active rigs, but then again, they don’t need to. That’s because in the last three years, the years of the downturn, rig efficiency has doubled, and is on its way to having tripled. Rigs that used to get well a month are now getting two, and approaching three. So if they get over 100 rigs working, that’s really like more than 200 rigs going, in the days of the boom, productivity-wise.

There are now about 800 wells that are waiting to be completed. These aren’t “DUCs,” wells that were drilled, but left uncompleted until things got better. No, these are wells that are waiting for a frac crew to get to them, or their sand to get there.

The state has since set another production record of over 1.2 million barrels per day in the weeks since the conference. State officials are projecting it will soon hit 1.6 million in 2021. Put another way, in the next three years, North Dakota expects to add the equivalent of almost an entire Saskatchewan with regards to production. But that’s not all. They’re gunning for 2 million barrels as early as 2024, an increase of 800,000 bpd from today. The Canadian Association of Petroleum Producers just put out a forecast saying it projects Canada will add 1.6 million bpd in production, but it will take until 2035.

Here, in Saskatchewan, one would be hard-pressed to find anyone who is nearly as great-guns as the North Dakotans. If they’re great guns, we’re water pistols, and not

even Super Soakers, at that. More like the dollar store ones that might shoot eight feet.

Moods have improved in Saskatchewan compared to a few years ago. Matt Axten, who heads up the Redvers Oil Showcase committee, noted as such in his remarks to the banquet on May 30. He spoke of putting on a brave face two years before, when things were really dire. But things are better now.

And they are better now. We’re hearing of companies being busier. One recently told us they don’t want to take on much more work yet. But we’ve also asked around if the vendor rates, what service companies charge their oil company customers have improved, and the answer is generally not much, if at all. One company told us they increased their rates and lost that work.

One thing did come up just as the edition was being wrapped up.

The North Dakota Pipeline Authority published a report on June 15 that showed nearly 100,000 barrels of oil per day were being trucked from Canada to North Dakota. Presumably most of that is from Saskatchewan. We will be looking into this in depth next month, but there’s a few things that we know already.

The Williston Basin Conference revealed that the opening of the Dakota Access Pipeline (DAPL) has had a profound effect. Whereas North Dakota Bakken oil used to trade at a discount to West Texas Intermediate (WTI), it is now trading at a several dollar surplus. If so, that may account for an enormous quantity of Saskatchewan oil going down south, to cash in on the premium.

This premium may also explain the bullish attitudes in Bismarck.

But as North Dakotan production grows, they will in short order maximize the capacity of DAPL, and there will again be a pipeline shortage. That means crude-by-rail will once again have to pick up the slack. It will also mean that whatever arbitrage advantage there is for Saskatchewan oil to be trucked into North Dakota might vanish with the surplus pipeline capacity.

Things need to pick up in Saskatchewan quite a bit for us to be so pumped up. The oil companies need to be making more money, and they need to be spreading more of it around. Maybe then we’ll see people pumped up, like they are a little south of Estevan.

“North Dakota has 2 million bpd on the horizon”

PIPELINE NEWS July 2018

We need to revisit Energy East and Northern Gateway right now Canada had better get its act together, immediately, on export pipelines.

I don’t just mean the Trans Mountain Pipeline, now owned by you and me and all other Canadians. I mean we need to revive Northern Gateway and Energy East right now.

Why? Because our only customer for essentially all our exported oil may not need or want much of it anymore.

I was able to score a brief but very insightful one-on-one discussion with Harold Hamm, North Dakota’s biggest oilman, on May 31.

Hamm is the CEO and largest shareholder of Continental Resources, and his company had been one of those who led the charge in North Dakota’s surge of oil production from 90,000 barrels per day roughly a decade ago to 1.2 million barrels per

day today.

I just happened to end up in the breakfast line with him. I quoted to him a line from a speech he gave eight years ago at that very same conference, and how I have cited that speech numerous times since then. That was my in, and he said it would be okay if I talked to him briefly before the presentation started that morning. You can find it here at www.pipelinenews. ca/1.23337588.

I asked Hamm if Canada is a competitor or compatriot when it comes to crude oil production.

“They’re definitely competitors,” he said, repeating, “They’re definitely competitors.”

He explained how American oil refineries want heavy, sour crude, and they are increasingly exporting their North Dakota light sweet crude since Canadian oil is

crowding them out of American refineries.

He also said America would become crudeindependent by 2020.

When I pressed him if this meant Canada was included, he said that America would be able to do it alone.

Therein lies an enormous problem for Canada, not just the oil sector, but our entire economy. What happens if our customer for 99 per cent of our exported crude oil decides it no longer needs us?

Trans Mountain is just a drop in the bucket in export capacity we would need if we suddenly have to find other customers for the roughly three million barrels per day we currently export to the U.S. Last week, the Canadian Association of Petroleum Producers forecast Canadian oil production will grow 33

A5

OPINION

FROM THE TOP OF THE PILE

By Brian Zinchuk

per cent From 4.2 to 5.6 million barrels per day by 2035. That number is obviously contingent on America buying most of that production. But what if they don’t need it, or desire it?

Make no mistake about it – it is oil wealth that funds not just Alberta’s economy and a good chunk of Saskatchewan’s, too, but much of the equalization formula.

Quebec’s damned near free child care? Oil. Their never-ending freeze on university tuition? Oil. It also funds a large portion of federal coffers.

If we can’t sell our oil to America, we’re in big, big trouble.

And what if Donald Trump is re-elected as president in 2020, the same time America could become crudeindependent, according to Hamm? They’re buddies, you know. It’s a good bet

it was Hamm who invited Trump to come to that conference two years ago, on the campaign trail.

That was the day Trump secured the Republican nomination and I just happened to get a chance to ask him about the Keystone XL pipeline.

Construction still hasn’t started on that pipeline. If America doesn’t want our oil (as Obama amply proved in delaying Keystone XL), we may never need it.

We’ve also found in recent weeks that Canada has no friend in President Trump. We are marching to a trade war with our southern “friend,” the friend who has gotten nicey nice with Kim Jong Un of North Korea. Kim’s spent the last several years trying to build nuclear missiles to aim at the White House. And yet Trump said the Canadian people are going to pay

for our prime minister saying he’s going to stand up for us.

Given the trade wars he’s started with Canada, Europe, and now China, does anyone really think, given the option, Trump wouldn’t turn off the taps on the Enbridge mainline and existing Keystone pipeline on a whim, just because he could?

We need to re-examine our export options immediately, reactivate all these export pipeline projects and get them built now, before an unstable “friend” in the White House totally destroys our economy with a tweet. We need to have options to export every available barrel overseas, and we need those options in two years if at all possible.

Brian Zinchuk is editor of Pipeline News. He can be reached at brian.zinchuk@ sasktel.net.

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PIPELINE NEWS July 2018

Northgate facility currently ships out Saskatchewan propane ◄ Page A2 lighter crude, and they’re influenced by different factors,” Day said.

“WCS, Western Canada Select, versus WTI, that spread is very important. WCS is an approximation of where heavy crude in Alberta and Western Saskatchewan is trading, but it doesn’t represent everyone there.

That spread is important, because the wider it is, the more you can pay for logistics costs to get that product to a U.S. destination. The opportunity there is likely in the centre Gulf,

in the United States.”

“The WCS spread is important, but in order for that to get where it needs to be, it’s really about where WTI is, and that threshold.

So our analysis has told us that heavy crude production could soon hit a point where it just doesn’t have anywhere else to go. And if so, they would be capped at what the price can be. If WTI can get above US$75 and stay there, there’s a very good chance there’s going to be a wide enough spread between the price in the Gulf they’ll pay for heavy crude, and the price they’ll

accept at the wellhead in Canada where we can get it moved by truck down to Northgate and transload it there.

Hauling heavy oil out of Northgate?

“That’s a possibility, absolutely,” he said.

“It’s probably only a three year opportunity. As infrastructure gets built, it wouldn’t be an opportunity going forward,” Day said.

That infrastructure he’s referring to is the long-delayed Keystone XL pipeline. If that’s in place, there’s no point in moving heavy oil by truck to

Jeremy Johnston, left, and Jeremy Nielsen gave Souris-Moose Mountain MP Robert Kitchen a tour of the Ceres Northgate Terminal on May 16. Photo by Brian Zinchuk

Northgate.

Long term sweet crude opportunity “The more long-term opportunity is the southern Saskatchewan sweeter crude and that’s more dependent on the spread versus North Dakota crude, and maintaining a level of a US$6.50 to $7 per barrel discount to North Dakota product. Unless we had a pipe connection to Northgate. Then the spread could be narrower,” Day said.

Right now there’s about a US$7 discount for Saskatchewan oil versus North Dakota oil. A publication by the North Dakota Pipeline Authority on June 15 shows nearly 100,000 barrels per day of Canadian oil is being trucked into North Dakota, so clearly this spread has been noticed.

“In order for that opportunity to work, we need to be able to load shuttle trains. And in order to load shuttle trains, we need to have infrastructure in Northgate that would cost US$12 to US$15 million – tanks and rack loading, the ability to load a train in 24 hours.”

It would be an enclosed loading rack, similar to what is seen in

Robert Day, CEO of Ceres Global Ag Corp., was in Regina on June 7 to talk to government officials. Photo by Brian Zinchuk North Dakota.

“If we could get a commitment from one of the refineries in the Pacific Northwest … that’s the opportunity. The heavy stuff would go to the Gulf, but the lighter stuff would go to the

Northwest,” Day said.

“We’ve been in touch with a couple refineries, it’s more than just one location.

“If we had the infrastructure, and the spreads are there and they made ► Page A7

PIPELINE NEWS July 2018

A7

Would it make sense to connect Northgate to Stoughton? ◄ Page A6 sense, we could do 15 to 20 trains a month. You have to have the supply, so you have to get your producer and refiner to come to terms on price.

That would be 100 cars at 700 barrels per car, or 70,000 barrels.

“Right now it’s an opportunity for anyone. We’re exploring all alternatives. Our goal is to maximize the value of what Northgate can offer,

and we see crude oil as a long-term opportunity we want to develop. We haven’t signed any exclusivity agreements yet.”

Pipeline With reference to a pipeline, instead of rebuilding the abandoned rail line connecting to Stoughton, pipelining oil to Northgate is an option, actually two. One could see a pipeline from Stoughton, another could be to the TEML terminal

at Steelman, about half the distance. Day said, “We see both of those as attractive, put it that way.

I would say we’d be willing to pursue either one.”

Doing so would also allow a propane pipe in the same ditch.

If oil companies did choose to ship their oil by rail out of Northgate, on the BNSF Railway, Day said it gives them access to Pacific Northwest refineries they don’t have

access to today. “That’s the big connection,” he said.

The proposed Trans Mountain pipeline expansion is different product, bitumen, which he doesn’t see as a competitor to light sweet crude.

If they went ahead Their link in the supply chain for crudeby-rail is only, US$1.50 to US$2 per barrel. Ceres would to act as facilitator, bringing together

the producer and buyer.

Indeed, any investment is predicated on being able to bring them together.

If the client wants Ceres to invest the money, backed by long term commitments, they’re willing to do it. Alternatively, the oil company can choose to do it themselves. “We are willing to look at partnering in a way that satisfies our customers’ requirements,” Day said. “Our goal is to

maximize the value of what we have at Northgate, and we’re willing to be flexible about how we do it.”

At US$65 per barrel, the economics don’t work so well for Canadian producers, but they are much better at US$75.

For heavy oil, they don’t need shuttle trains, so they can do transloading to manifest trains. “We can have ourselves set up in two weeks” he said.

Combination expected to top 100,000 boepd next year ◄ Page A3 number of active drilling rigs.

Background Raging River’s May 14 press release noted the company’s average daily production for the first quarter of 2018 was 24,188 boepd, (93 per cent oil) and it had drilled 126 gross (112.7 net) wells during that time with a 100 per cent success rate.

It had also drilled a Duvernay light oil discovery well in the Pembina (Pigeon Lake) area of central Alberta.

Raging River started operations in 2012.

Headed by Roszell, Saskatchewan’s 2015 Oilman of the Year, it had initially planned to sell in its early years, but that plan was derailed when the oil downturn hit in 2014. In July 2016, the company was talking about plans for spending $3 billion in capital expenditures in Saskatchewan over the next 10 years, and a further $1 billion in operational expenses.

However, things have changed since then. As the oil industry has improved, in March the company has said it was initiating a process to review its

strategic positioning. In a March 5 press release, the company said, “In connection with the repositioning process, the board intends to undertake a comprehensive review to identify and consider a broad range of alternatives to enhance shareholder value, including, but not limited to, a merger, corporate sale, corporate restructuring, the sale of select assets, the purchase of assets, or any combination of the potential alternatives.”

The company has long been one of the most active drillers in the Saskatchewan Viking play,

often running neck-andneck with Teine Energy Ltd., the other significant operator in that area. In July 2016, when much of the oilpatch was in its greatest slump in recent years for drilling, Raging River placed fifth on the top five active operators list for the entire country on June 7, with three drilling rigs working.

At the time, Roszell attributed that to their shallow wells taking only 2.5 days from spud to release.

Baytex has a history in Saskatchewan spanning over 20 years, in particular

in their Soda Lake field, south of Maidstone, in its Lloydminster core area. When Pipeline News visited this field in February 2017, they had one rig drilling multilateral wells, and one of their main methods of production is waterflood enhanced oil recovery. Baytex’s June 2018 presentation, which came out with the merger announcement, said they have two rigs working in that area and intend on continuing that into 2019.

The combined company will have an estimated average annual production of 100,000 to

105,000 boepd, of which 85 per cent will be oil and natural gas liquids. Their exploration and development capital program will be between $750 to $850 million, representing a five to 10 per cent production growth.

During the conference call, LaFehr noted expansion in the East Duvernay and Lloydminster heavy oil regions and using the Viking and Eagle Ford for free cash flow.

Eagle Ford Baytex has 36,000 boepd (78 per cent oil and NGL) in the south Texas ► Page A8 info@cpenergy.ca

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A8

PIPELINE NEWS July 2018

Baytex plans on being self-funded, and increasing activity

◄ Page A7 Eagle Ford play. Wells that commenced production in the first quarter of this year were bringing in approximately 1,750 boepd per well, a 20 per cent improvement from wells a year before. Two wells produced approximately 2,400 boepd in their initial 30 days of production.

East Duvernay Their East Duvernay region, which from Ponoka to Sylvan Lake, then north to Pigeon Lake and back to Ponoka, was a highlight of the deal. Raging River holds a 100 per cent working interest in greater than 260,000 net acres of lands in the emerging East Duvernay shale oil play in

central Alberta. The release noted the Duvernay is among the largest oil and gas resources in Western Canada with activity in the east shale basin increasing over the last three years in pursuit of light oil (average 36-42° API). During the first quarter of 2018, Raging River embarked on a three well evaluation program, which included an initial discovery in the Pembina area that has produced at an average rate of 430 boepd (88 per cent light oil and NGLs) in its first 80 days since coming on production on March 23, 2018. The well continues to produce at strong rates with the last seven days averaging 400 boepd (88 per cent light

oil and NGLs). Given the success of the exploration program, four additional locations are being licensed offsetting the discovery well in preparation for an expanded capital program in the second half of 2018 and a 2019 plan that will include 12-20 net wells.

Viking In the Viking, Raging River has built a dominant position in the Viking light oil resource play in western Canada with over 460 net sections of highly prospective land and approximately 10 years of drilling inventory at the current pace of development. Production in the Viking averaged 23,000 boepd in the first quarter of 2018 (approximately 36°

API). The Viking generates an exceptional operating netback of approximately $44 per boe at a WTI price of US$65 per bbl with well payouts averaging approximately 10 months.

Raging River currently has four drilling rigs running and anticipates a continuous program through year end. The Viking extended reach horizontal results continue to exceed expectations with multiple new, previously untested sections being proven as economically drillable during the first quarter. The Viking is expected to continue to generate significant free cash flow in the current commodity price environment. Waterflood initiatives

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continue to advance with continued positive results at Gleneath, Eureka, Plato and Forgan.

Peace River The Peace River region, located in northwest Alberta, has been a core asset for Baytex since operations commenced in the area in 2004. Through innovative multi-lateral horizontal drilling and production techniques, Baytex’s Peace River properties generate strong capital efficiencies.

Baytex’s recent northern Seal well (13-leg multilateral) generated a 30-day initial production rate of 900 boepd (facility constrained); a total of 10 wells are anticipated to be drilled in the area in 2018. Production averaged 16,500 boepd (90 per cent heavy oil) in the first quarter of 2018.

Baytex has a dominant land position of 725 net sections and an inventory of approximately 350 drilling locations that generate 50 per cent to 75 per cent IRRs at a WTI price of US$65 per bbl. Baytex expects to have rigs running in the second half of the year as it continues to build

He started with a ’54 Chevy: Tony Day of Carnduff passes at 85

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operational momentum heading into 2019.

This area will see an increased two-rig drilling program through 2019.

Lloydminster Baytex’s Lloydminster region is characterized by multiple stacked pay formations at relatively shallow depths. The area has been successfully developed through vertical and horizontal drilling, water flood, steam-assisted gravity drainage operations and, more recently, the implementation of polymer flooding to further enhance reserves recovery. Baytex has adopted, where applicable, the multi-lateral well design and geosteering capability it has successfully utilized in Peace River. Lloydminster drilling locations generate 50 per cent to 110 per cent IRRs at a WTI price of US$65 per bbl. Production averaged 10,000 boepd (99 per cent heavy oil) in the first quarter of 2018. Baytex will recommence its Soda Lake multi-lateral drilling program in June and expects to have two rigs running in the second half of the year.

Carnduff – On May 24, a legend of the southeast Saskatchewan oilfield, Tony Day of Carnduff passed away peacefully at the Galloway Health Centre, Oxbow, on May 24, 2018, at the age of 85.

Founder of Fast Trucking Service and numerous other companies, Day was also well known for his philanthropy.

Tony is survived by his loving wife, Vi; four children, Linda (Ross) Apperley (their daughters, Rachelle & Kiana), Teresa (Mitch) Kyle (daughter Cheryl), Dennis (Carmen) (their children, Emily (Tyler) Fernell & Rilee, Harly (Brook) Nevaeh & Haizley, Julia and Nathan), and Larry (Lori) (their children, Lexi, Levi and Lucas); sister Dorothy Armstrong; sister-in-law,

Mona (George) Connelly; also numerous nieces, nephews, cousins, and friends.

A funeral service for Tony was held at the packed Carnduff Arena on Tuesday, May 29, 2018. Reverend Kathy Kyle officiated. In keeping with his life, his casket was chained down to “Gerta,” a bed truck he owned for many years, to be taken to the Carnduff Cemetery.

His passing was recognized in the House of Commons by SourisMoose Mountain MP Robert Kitchen, who made a statement in Parliament on May 25.

Tony was awarded the Southeast Saskatchewan Oilman of the Year Award in 1999, and inducted into the Saskatchewan Oil and Gas Hall of Fame in 2009. In 2017 he was presented with the Canada 150 Senate Medal.

On July 27, 2017, Pipeline News sat down at Tony and Vi’s kitchen table and spoke with them about their 60th year in business as Fast Trucking. The story owf their business is in many ways part of the story of Tony’s life. You can find the story at www.pipelinenews.ca/1.23315454

MS RS

PIPELINE NEWS July 2018

A9

North Dakota is getting a new oil refinery

MERIDIAN ENERGY GETS FINAL PERMIT FOR DAVIS REFINERY AT BELFIELD

By Brian Zinchuk Bismarck, N.D., Belfield, N.D – A new oil refinery at Belfield, N.D. has cleared its last regulatory hurdle and construction is expected to start very soon.

On June 13, Meridian Energy Group, Inc., announced that the North Dakota Department of Health (NDDoH) air quality division has issued the permit to construct (PTC) for the Davis Refinery at Belfield.

The issuance of the PTC by the NDDoH comes 18 months after the initial application was filed by Meridian and is based on a thorough review of the Davis Refinery application documents, and a full three-month review of comments received during a 45-day public comment period.

This marks the first time that a full-conversion refinery of this size and complexity has been reviewed and approved as a “synthetic minor source.”

Meridian said in a release that securing this classification reflects its innovative design, and dedication to attain the lowest achievable emission rates ever seen in a full-conversion

oil refinery. Now that the final PTC has been issued, Meridian will proceed with detailed design, engineering, procurement and construction of the Davis Refinery.

A Meridian spokesperson told Pipeline News on June 22 that “Meridian will look to break ground on the Davis Refinery in the next two weeks.”

“We fully appreciate the thorough and meticulous review performed by the NDDoH, which held us accountable at every phase of the review process,” said Meridian CEO William Prentice. “Meridian’s design efforts, which included modifications and improvements made as a result of their rigorous review, have ensured that the Davis Refinery will operate in full compliance with the law, and in a manner that is responsive to the concerns of the local community. The Davis Refinery will indeed be the cleanest refinery on the planet when completed.”

Prentice then added, “Publication of this final permit validates the enormous amount of work performed by the entire team and the Davis PTC also represents the culmination

of the tireless efforts of the NDDoH staff. Meridian and its team utilized the current limits of technical innovation throughout this process, and never stopped seeking opportunities to make the Davis Refinery as clean as it could possibly be. We hope Davis becomes the new blueprint for all refinery projects that follow it.”

On May 22 at the Williston Basin Petroleum Conference in Bismarck, N.D., Lance Medlin, executive vice president, projects, with Meridian, gave a presentation on the project. After that presentation, he spoke at length with Pipeline News about their plans.

Phase 1 will be under half a billion dollars, and a similar amount is expected for Phase 2, according to Medlin. The initial phase will be a 27,500 barrels per day (bpd) hydro-skimming plant, with full commercial operation in early 2020. It will produce finished gasoline, kerosene/jet-A, ultra low sulfur diesel and low sulfur fuel oil (ATBs).

ultants

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The planned expansion will bring that number up to 49,500 bpd.

The site is southwest of Belfield, immediately adjacent to the BNSF Railway Fryburg rail terminal.

He expects there will be about 1,000 workers in the construction phase.

It will take 18 months from scratching dirt to completion. Asked how they will do it so quickly, he said, “Trade secrets,” but added that it will all be U.S.-sourced. “Anything not built in the U.S. will be by exception, by either licensed exception. I don’t have any intention, and it is my call, of shipping any work outside of the U.S.” “We’ve got plenty of fabrication capability in the U.S., and it is tremendously underused right now. Even though we are coming out of our downturn, we are still in a downturn,” Medlin said.

“The majority of the facility will be modularly constructed. You’ve got to understand that a lot of the cost and schedule

Lance Medlin spoke to the Williston Basin Petroleum Conference in Bismarck, N.D., on May 22. Photo by Brian Zinchuk impacts affecting other facilities here were due to a stick-built design, and you’ve got the schedule impact of just the natural winter in this region. So modular fabrication, with onsite erection of modules, is the way to get it built within 18 months.”

He mentioned that there is a lot of fabrication capacity in Texas and Colorado, but also in

Canada. “We’re talking about a lot of modules. A lot,” he emphasized. “So we’ve just taken the model and gone through it and modulized the design. It’s a lot of modules. It’s way too many for one yard.

It’s way too much risk for one company to build all the modules. It has to be spread out.”

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Phase 1 will be 27,500 bbl., Phase 2 takes that to 49,500 bbl. ◄ Page A9 EPC firm for sourcing those modules.

With the air quality permit now in place, all the permitting is now in place.

The land is all secured.

Asked in May how many people they had working for them, he responded, “How many people, or how many companies? We have

six major contracts with major companies, burning manhours right now. We have a multimillion dollar contract burning manhours with our EPC (engineering, procurement and construction) contractor, who has already been selected and not announced. We are negotiating our EPC cost, as they are finalizing our feed.”

In May there were probably 200 people working on the project, principally engineers, project control, supply chain and procurement. In their early stages, they had 30 people on board, including contractors, in the U.S., but there were probably another 50 people in Venezuela working on drafting.

The company is raring

to go. Asked how long it would take to get working once the permit was in place, Medlin enthusiastically said, “If it happens on a Saturday, it might take us until Monday. We’re ready.

We’ve got yellow iron on standby. We have all of our contracts ready. We have LOIs (letters of intent) issued, MOUs (memorandum of understanding). If

I can get the permit on a Friday, I can have surveyors and yellow iron on site 24 hours later. And I will.”

At this point, the company is backed by private equity.

Regarding the implantation of Phase 2, Medlin said, “There is no desire to wait between the completion of Phase 1 and the start of Phase 2. There’s

no commercial desire. We want the revenue. And there’s no permitting reason to wait. We’re permitted for the entirety of the facility.”

They’re not looking at a refinery in Canada, but they are in the U.S. “We are going through the regulatory process for our next refinery,” he said, but he can’t say where.

North Dakota’s biggest oilman sees Canada as a competitor, not a compatriot

By Brian Zinchuk Bismarck, N.D. – Continental Resources chairman and CEO Harold Hamm has had a lot to say about energy independence for the United States in his remarks to the Williston Basin Petroleum Conference over the years.

With American oil production again heading towards new heights, where does he see Canada in this equation? As a competitor, not a compatriot.

The head of the largest oil producer in North Dakota spoke to Pipeline News oneon-one on May 24 at this year’s version of the conference, which alternates between Bismarck, N.D. and Regina.

Pipeline News: Where does Canada fit in your idea of energy independence?

Harold Hamm: Canada? They are, of course, energy independent, as far as that country. They’ve got gas that they export, and have for a long time, and certainly export a lot of oil, from the tar sands.

So they’ve been energy independent.

P.N.: How do we fit in America’s equation, because 99 per cent of our oil exports are to the United States?

Hamm: That’s right.

But Canada has got to get a pass-through system going.

And they are. They basically bought refineries down here and everything to support their tar sands, much to our chagrin, frankly, and transformed those complete refineries to complex, heavy

crude refineries. It really cost America a lot. That’s why we have to export. We didn’t have sufficient refinery space for sweet crude.

P.N.: How much are you exporting now, for Continental?

Hamm: You know, ours is varying, but its increasing. It’s a small percentage, at this point, compared to our production. We’re exporting more and more.

P.N.: Do you see Canada as a competitor or a compatriot?

Hamm: They’re definitely competitors. They’re definitely competitors.

P.N.: Two years ago, TransCanada was talking about building a pipeline from Williston into Sas-

Harold Hamm speaks at the 2018 Williston Basin Petroleum Conference. katchewan, which would have tied into the Energy East project, and would have been able to ship Williston oil into Eastern Canada. Now, that project is dead because Energy

East was killed. Would you have taken advantage of those export opportunities?

Hamm: We would have, if it had been created.

That was Line 9?

P.N.: This was a totally different line. They were going to convert a 42-inch gas line to oil. It was going to a 1.1 million barrel capacity, and it was going to have a 300,000 barrel per day lateral from Williston to Moosomin, Saskatchewan.

Hamm: Okay. Uh, sure. Everybody’s trying to share space and whatever to get crude to markets from out here. Not all these things work, you know.

P.N.: One last question: Do you think

America, by itself, can become crude, independent, or do you think the United States, and Canada, together, can do it.

Hamm: No, I think the U.S. Obviously we’re on a trajectory right now that will see energy independence in America in crude oil and liquids by 2020. So, yeah, we’re getting there ourselves.

P.N.: So if Canada is selling three million barrels a day to the United States, then you have to export three million barrels?

Hamm: They’re exporting more than that.

I mentioned yesterday that almost six million barrels of refined products is being exported every day, and a lot of that is out of Canada.

PIPELINE NEWS July 2018

A11

Husky applying ‘lessons learned’ in proposed new pipeline

By John Cairns Battlefords News-Optimist North Battleford Husky officials say they are applying all the lessons learned from the 2016 North Saskatchewan oil spill in designing new pipelines that will run from Lloydminster all the way up to the RM of Frenchman Butte.

Husky Midstream held an open house Thursday afternoon at the North Battleford Legion hall. It was a comeand-go event to provide details on plans for three pipelines along the route.

One would be a 20-inch pipeline which would transport the crude oil product back to the Lloydminster area from thermal sites in the northeast. The other is a eight-inch line to transport condensate to the thermal sites, which will blend with the heavy oil to be brought back.

The two lines would run for 52 kilometres from Lloydminster through the RMs of Britannia and Eldon and then to Sandall Junction and Celtic Junction in the RM of Frenchman Butte.

There are also plans for a 20-inch raw water supply pipeline. The route is considerably shorter, running from the Husky Direct Intake High Lift Station just to the south of the original pipeline crossing site, and run to Sandall Junction. The raw water, which is lifted

from the North Saskatchewan River, will be used for production.

All three pipelines will cross the North Saskatchewan River; however there is a change in location from the pipeline that ruptured in 2016.

According to Husky spokesperson Travis Davies, “We’ve learned a lot from 2016.”

The main lesson they learned, he said, is to avoid slope. The new pipeline being proposed is located four kilometres downstream to the east of the original site where the spill happened.

Ground movement had been identified as causing the rupture in the line, resulting in 1,570 barrels of oil being spilled, a sizable portion ending up in the North Saskatchewan River.

Among the changes, said Davies, is the “concept of going hilltop to hilltop, to avoid slope altogether to avoid geo-active areas. You’ve got thicker pipe, better pipe. You’ve got a ton of technology in terms of analytics that can tell you what’s going on with the pipe in place, and improved procedures at our control room as well that set out timelines where if you hear an alarm, it gets dealt with in this way in this amount of time.

“Some alarms are immediate shutdown as well. So that’s an important aspect as well. Part of the point here is to

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get people to understand what we learned and how we are applying it to the new project.”

Also, the pipeline will be 80 metres below the river. The pipeline will cross at the same spot as the TransGas crossing, said Davies.

The three pipelines would end in the area where there is new production. They also hook up to pipelines that will take the product further north towards the Paradise Hill area. There is an existing junction at Sandall Junction that will

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PIPELINE NEWS July 2018

Construction planned for fall

◄ Page A11 week in Melfort and in Prince Albert. They held open houses in Lloydminster and Maidstone last fall.

The hope from Husky is that they get through the regulatory approvals and start construction this fall. It would be a 10- to 12-month construction phase, “at which point we would put it into service,” said Davies. The capital cost of the project is estimated at $130 million.

The open houses saw considerable interest This was the scene at the Legion hall in North Battleford on from people who want to know what the pipeJune 14 as officials from Husky Midstream provided details line project is about, and what changes are being of proposed pipelines running from the Lloydminster area up made. to the RM of Frenchman Butte. The new pipeline will cross “They want to know what’s different this time,” said Davies. They’re also interested in jobs, underneath the North Saskatchewan River about four kilometres downstream from the previous pipeline location where the oil he said. About 300 to 500 jobs are expected to be spill took place in 2016. Photo by John Cairns created during the construction phase.

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Over 1,500 attend Redvers Oil Showcase Redvers – The Redvers & District Oil Showcase saw beautiful weather for its May 30-31 event, and it was a perfect metaphor compared to the last show two years ago.

Then, it was cold, stormy, and generally miserable. And that fit the mood very much with those who were in attendance in 2016, whose companies were struggling, and many of whose companies had seen tremendous layoffs. Matt Axten, chair of the show, alluded to as much in his comments to the sold-out banquet crowd on May 30 this year.

He noted how they had put on a brave face two years ago with the show, but this year, there was more support.

This year, moods were much better. The show’s exhibits and banquet were

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Oil showcase chair Matt Axten noted how we are now all business partners, in a very expensive pipeline. both sold out.

“A lot of us are competitors, but as of recently, we’re all business partners, too. We just bought a pipeline. Congratulations everyone. We own a really ► Page A13

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PIPELINE NEWS July 2018

A13

This year moods were much better

◄ Page A12 expensive, highly controversial pipeline,” Axten noted at the banquet presentation, referring to the recent purchase of the Trans Mountain Pipeline and its expansion by the federal government from

Kinder Morgan.

The banquet speech was by Pipeline News editor Brian Zinchuk.

Entitled “I didn’t see their horses,” he spoke about how the Saskatchewan oilpatch has been portrayed in the media, ► Page A14

School Grade 3 Northern Mat0126-3000px Several classes of Redvers School made their way to the show.

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PIPELINE NEWS July 2018

Positive feedback from oil showcase exhibitors ◄ Page A13 and about how hypocritical its critics have been. His conclusion was that those in the oilpatch simply want to provide for their families and are fundamentally good people, and the rest of Canada needs to acknowledge that.

Rhonda Martin, administrative assistant for the committee, said just over 1,500 people attended. “I think it went over well. I talked to a lot of exhibitors and chatted with a lot. Everybody had positive feedback,” she said.

Rescue Canadian Plains Energy’s Dale Ziegler and support STARS

By Brian Zinchuk White City – STARS Air Ambulance’s annual Rescue on the Prairie fundraiser has launched for this year, and each year, there’s a representative from the oilpatch.

Dale Ziegler, president of Canadian Plains Energy, is taking up the torch (or perhaps the flare) for the oilpatch this year.

The other participants include JoeAnne Hardy, president, WBM Technologies; Sarah Johnston, Vice President of Sales and Marketing, GMS; Tyler Crozier, owner/operator, Crozier Ag; and Garth MacDonald, president and CEO, G-Mac’s AgTeam Inc. “They asked me a few months ago,” Ziegler said from their new White City shop on June 15.

He noted the province got an extra reminder of the importance of STARS after the Humboldt Broncos bus crash a few months ago. “They help everybody,” Ziegler said. “What the hell, I better do it.”

Ziegler calls Francis home, and he’s a local volunteer firefighter there.

They have done training to assist STARS, and he noted STARS has come to the community many times.

“They rely on the fundraising. That’s the only way they can stay in the air,” Ziegler said.

Ron Carson, who was a participant in Rescue on the Prairie several years ago, coaxed Ziegler to take part. They have worked together for many years.

Ziegler’s current goal is $50,000, but he said, “That’ll be the bare mini-

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Dale Ziegler mum. I hope to well exceed that.”

As of June 26, he had already raised $16,725.

The Rescue on the Prairies takes place on September 13, 2018.

The link to the event website is www.rescueontheprairie.ca.

Ziegler’s personal page, where donations can be made, is support.stars. ca/goto/daleziegler.

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North Dakota on a sharp growth curve in oil and natural gas

By Brian Zinchuk Bismarck, N.D. – The forecast for North Dakota in almost all areas of petroleum production is on a sharp curve upward, with oil and natural gas production expected to nearly double in coming years, limited primarily by infrastructure keeping up.

That was a big part of the message by Lynn Helms, long-time director of the North Dakota Department of Mineral Resources, when he addressed the Williston Basin Petroleum Conference in Bismarck, N.D. on May 23.

Helms started out by noting North Dakota has 14,457 active wells, of which 12,627 are Bakken/ Three Forks, and the remainder are conventional.

There are 1,653 inactive wells, and 916 waiting on completion. “It looks like only 110 of those are true what you would call DUCs (drilled, uncompleted),” said Helms. “It looks like industry has given us a new normal, which is 800 wells in the process of finding a frac crew, getting on the schedule, getting the sand, the water and the weather for everything right,” he said.

There’s about a 15-month supply of permitted wells, totalling 1,888. There’s 13,451 wells approved and ready to permit for increased density drilling, or about an 8.5-year supply. “It gives you some indication of at least of how long this industry plans to maintain this drilling activity level.”

He noted their ultimate estimate is 55,000 to 65,000 wells eventually, and just over half are now in the pipeline.

“We’re just ending the first period of the football game. We haven’t even blown the whistle to change ends of the field, in the first period of the football game,” Helms said.

As of the end of 2017, he noted, “Your industry has brought $127 billion of capital from all over the world and put it into North Dakota’s economy.

Thank you.”

He said there’s another $348 billion to go over the next 20 years.

He noted technology used in the Bakken is being used in the Eagle Ford, Niobrara and Permian shale plays, but new-well oil production per rig is still highest in the Bakken, with approximately 1,400 barres per day production.

Oil prices had, by the time of the conference, reached the point where it was now economical to work beyond the core of the Bakken play. “At today’s oil prices, economics reach way beyond the core, all the way to the Canadian border,” Helms said. “The entire Bakken is at play again.”

There were, as of May 23, 65 active drilling rigs in North Dakota, up five from a week before.

Pointing out that the oil industry has seen a trillion dollars of underinvestment during the downturn. “What that means is that some time, not too long after 2020, prices have to make a correction to bring that investment back and bring that production back.

“You bring that to North Dakota and what does that do? We think we see moderate rig growth

this year, next year, and in 2020, but in 2021, when we see that price correction, we see rigs coming back, really, really intensely.

“We’re looking at, in the early 2020s, well over 100 drilling rigs. Keep in mind, those drilling rigs are twice as efficient today as they were just three years ago. Three years ago, a rig could get one well a month. Today it’s two wells a month, and many in the industry are exceeding that. Many are approaching three wells a month, and expecting to get another 20 per cent of efficiency out of these drilling rigs,” Helms said.

In forecasting North Dakota’s oil production, the North Dakota Pipeline Authority put out two cases. Case 1 see a rapid rise to 1.6 million bpd by 2021, and 2 million bpd by about 2024, peaking at 2.35 million bpd in 2033.

Case 2 starts off slower but has a similar, if lower rise.

It forecasts 1.6 million bpd in 2024, and a slower rise to 1.95 million barrels in 2034, but never quite making it to 2 million barrels.

“One of the things we need to think about is how is our crude oil going to get out of North Dakota?”

Helms asked. He noted the addition of the Dakota Access Pipeline (DAPL) means there is currently excess pipeline capacity.

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Even with those five new plants, there will be a need for another tranche of five gas plants in three to four years. And that pattern

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will likely require another five plants in the years that follow.

He noted there is currently an open season on the Alliance Pipeline (which runs from Fort St. John, B.C. to Chicago).

“Some of that is reserved for North Dakota gas, and ► Page A16

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totally full. Even expanded DAPL is totally full. Even the refineries that are planned in North Dakota are totally full, which means either a return to rail cars, or we need to have begun, two years ago, planning the next crude oil pipeline.

“We’re looking at Keystone, we’re looking at some other options. We’re talking to industry about it. But my message to you, you’re mainly upstream and midstream folks – if somebody comes to you with a pipeline proposal for an export pipeline – commit barrels. Get the pipeline built, because there is no time to get the project started and permitted,” Helms stressed.

Natural gas production is on a strong growth curve as well, and the gas:oil ratio has been increasing.

“We need to be building 2,000 to 2,500 miles of pipeline every single year from now to 2025.

So there is no time like the present to get your right-of-ways,” he said.

Recently, that number has been as low as 700 miles of pipeline per year.

Five gas plants are

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North Dakota will need more oil and natural gas export pipelines very soon as current pipelines will soon fill ◄ Page A15 that’s going to help us a great deal. There’s the potential to increase the capacity going into Chicago by 400 million SCF per day, and that’s great news for our gas processors.

Even with that, and the Northern Border pipeline, there is no

additional capacity for gas export by 2026, so a major project is going to be needed. “We’re going to have to look at some other markets for North Dakota gas. I don’t know what that is. I hope it’s fertilizer. I hope it’s plastic, or a pipeline going somewhere to supply our

friends in California or Washington with natural gas.

“This is some of the wettest gas on the face of the earth,” he said of natural gas liquids.

“This is still a fivegeneration oil play. We’re only halfway through the first generation,” Helms

said.

There are four enhanced oil recovery projects that will be tested in the field this summer, he noted.

Finally, the workforce is an important issue.

“We peaked out at about 56,000 people working in this industry in 2014.

That dropped 20,000 jobs, to 36,000, in 2016. In order to accomplish what is ahead of us, we need to add 6,000 jobs this year, 5,000 next year, 10,000 jobs in 2020, and another 4,000 jobs in 2021, for a total of 63,000 jobs in this oil play by 2020.

“Where are we going

to house them? Where are their kids going to go to school? What are they going to do for recreation? We need to be talking to our western communities about how they’re planning for these people coming back, because they’re all coming back, plus another 7,000.”

Border insulators expanding to Red Deer

By Brian Zinchuk Redvers – Estevanbased Border Insulators is setting up a new operation in Red Deer, Alta, according to Ryan Saxon, president.

Pipeline News spoke to him as he was leaning on an utilidor sample they had on display at the Redvers Oil Showcase on May 31.

“Things are starting to come around a little bit,” Saxon said. “It’s not too bad.”

In recent years they put in a bigger sandblasting setup in the back of their yard.

“With the tank side of

things, R&R Tanks, we’re expanding a bit of that.

“With Border, we’re putting Border Insulators in Red Deer, Alberta, now.

We’re expanding to Alberta.

We were in Drayton Valley for the last couple years, but we’re going to focus on Red Deer. We’re out of Drayton.

My brother lives in Red Deer, so he’s going to run it out of there.

Devin Saxon is the one setting up the Red Deer operation this summer.

“Everything’s registered in Alberta. We’ve got to find a shop in Red Deer now. We were renting off an outfit in Drayton Valley, but we’re done there now.”

He said they’ll likely have about a half a dozen people working there.

Red Deer was chosen because Devin lives there and it’s more centralized, Saxon said.

This past winter they were active with their frac heating operation, doing it both on site and at the water source at Rafferty Reservoir.

Asked how things were going at for them at the show, he said, “Today is a little slower. Yesterday was good.”

It’s important to be a part of it so that people know you’re still around and what you offer, he said.

Ryan Saxon demonstrates a sample utilidor. Photo by Brian Zinchuk

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I didn’t see their horses: speaker takes on oil critics

By David Wilberg Redvers – The guest speaker at this year’s Redvers & District Oil Showcase delivered a speech that praised the people in the oilpatch and took aim at the industry’s critics.

Brian Zinchuk, the editor for Pipeline News, delivered his speech on May 30 at the biennial showcase’s banquet in front of about over 400 people.

During his 10-year run as the editor for Pipeline News, he has been to most of the businesses present at the banquet.

“And over 10 years of doing Pipeline News, do you know what I’ve found? Most of you are pretty damn good people,” he said. “Most of us, and I include myself, in the oilpatch, are good people who simply want to provide for their family. We work hard, and we just want to get home to our bed before someone else does.”

Zinchuk told the crowd he used to be a pipeliner and an excavator operator, so he understands the demands of work in the oil and gas sector.

“But to so many

people, especially in Central Canada and the Left Coast, we’re evil,” said Zinchuk. “We’re horrible people. We’re the oil industry! We’re the devil.”

He noted people in the patch follow strict environmental and safety rules, with environmentalists and safety people breathing down the necks of those in the sector.

In the Manitou Sand Hills southeast of Lloydminster, for example, an environmentalist found a fern on a proposed flowline right-of-way. The right-of-way was moved, at a cost of tens of thousands of dollars.

Zinchuk also compared the standards of Canada versus other oil producing nations.

Women in Canada are allowed to work, vote and drive, unlike Saudi Arabia.

Yet protesters don’t picket Saudi oil tankers coming up the St. Lawrence River.

He voiced his support for Alberta’s threat to turn off the tap on the existing Trans Mountain pipeline to the Lower Mainland of British Columbia.

He said 80 per cent of the petroleum servicing the Lower Mainland comes through that pipe,

even if the oil goes to refineries in Washington state. Those refineries then supply a lot of the Lower Mainland.

Zinchuk also suggested a toll for B.C. products shipped through Alberta and Saskatchewan via the Alliance Pipeline.

“The people in this room would like to know, how long are those earth muffin protestors going to be able to do that, tweeting on their plastic phones, wearing synthetic clothes, holding up plastic signs, which they brought in their gas guzzling SUVs, their oil protest? Maybe they’ll paddle out in their fibreglass kayaks.”

Zinchuk pointed to a series of articles last October in the Toronto Star, Global News and National Observer, which targeted on the Saskatchewan oilpatch. The stories, Zinchuk said, were part of a much larger project, backed financially by the Corporate Mapping Project (CMP).

The CMP’s website notes, “The tremendous concentration of power and influence we see in the fossil fuel industry today places sharp limits on our democracy.”

After gunning for

Pipeline News editor Brian Zinchuk was the guest speaker during this year’s Redvers & District Oil Showcase. Photo by Phyllis Stroud conflict.

“That’s what energy independence means to America. Canadian oilsands oil is diluted with condensate. Middle eastern oil is diluted with the blood of American soldiers, sailors, airmen and marines.”

Zinchuk asked how much blood has been spilled for Canadian oil, and how many wars have been fought over it.

“Our oil is not stained in the bloodshed of war.

We live under some of the most stringent environmental, safety, and moral rules imaginable.”

Environmental standards have become much tougher since Zinchuk worked on the Alliance Pipeline. National Energy Board-regulated pipelines aren’t built in the summer months any longer.

He believes it’s time for critics of the oil industry to realize that the oil industry is one of the most important on the planet.

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H2S in Saskatchewan, subsequent stories later in the month targeted petrochemical production areas in Ontario, the other end of the pipeline.

Zinchuk went to the student film portion of the project, when it was screened at the University of Regina’s School of Journalism last year. It “laid out all the warts of our industry in Saskatchewan,” Zinchuk said, and left him fuming.

Two older women behind him were expressing their disgust with the industry. Zinchuk reminded them they didn’t have horses tied up outside, and every person in the room wore synthetic clothing made of oil.

“The hypocrisy of oil critics in this country is unbearable, especially if you wear fire retardant coveralls for a living,” said Zinchuk.

Zinchuk also looked at the trend towards energy independence, which is important to the U.S. Harold Hamm, the CEO of Continental Resources and a key player in the U.S. sector, has said it means Americans don’t have to send their children to be killed in overseas

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PIPELINE NEWS July 2018

Swayze’s putting drone to good use

By Brian Zinchuk Redvers – Swayze's Concrete Ltd. has found that applying cutting edge drone technology to measuring piles has dramatically cut time, expense, effort, and the possibility of injury compared to the old-fashioned way of walking piles.

The Carnduff-based firm had its drone on display at the Redvers Oil Showcase on May 30-31.

Jamie Didrick is their crusher manager, based in Carnduff. Randy Swayze runs the business with his

brother, Ryan, who operates out of Weyburn.

Didrick said they got their drone two years ago in October, and started to use it right away. The payoff was immediate.

“We used to walk the piles with a Topcon,” he said, referring to a surveying device.

When deploying the drone, you set a bounding box on the iPad screen, picking four points on a box for it to fly within. It sets a hard boundary that the drone will not stray from.

Jamie Didrick’s life as a crusher manager has dramatically improved with the implementation of a drone to precisely measure piles and other things. Photo

by Brian Zinchuk

The drone takes pictures constantly. Those images are pieced together in the software, creating a 3-D model of the terrain below it.

Once the model is created, you can select the pile of material you want to measure and draw a polygon around it. This can be done on the iPad, but they find it’s easier on a computer. You can change the units to cubic metres, cubic yards, tons, or whatever you require.

Didrick said the volumes it measures are accurate to within one per cent, as opposed to two to three per cent with the old method. And that makes a difference.

“The first year I did 213 flights, so almost daily,” Didrick said. “Three times a week for sure.”

They measure piles for rural municipalities and other customers.

“It’s a lot better than walking it, too, because we can measure it when we’re halfway through, or when we think we’re getting close.

And if we need to add another 1,000 yards to what our pile is, we can fly it right away again,” he said. ‘ “Whereas walking it takes a lot. It’s strenuous,

and it’s hard on the body.”

The site he showed as an example took 26 minutes to fly, with 32 piles. He explained, “That would take you probably a week to walk.”

“It’s far safer, too” said Swayze. “In winter time, piles are frozen, so when you try to climb a frozen pile, you slide off.”

Didrick said, “Even in the summer, rock is unsure footing. You save time, you save money and you save people. Lots of times you would have two people.”

“I’ve flown it in -21 C. It eats the batteries faster.

It’ll fly in 40 kilometre winds, too. But I wouldn’t go out with a lot of wind in the winter.”

“The nice thing about this is we don’t fly it. It goes on a grid. If it gets off that grid, if it blows off that line it’s supposed to be on, it will shut down and return home. You can send it back up and it will go to that spot it left off.

“We don’t own it.

We pay a lease per year from a company from San Francisco. We pay $25,000 American.”

That comes with the software and continual upgrades, as well as insur-

This iPad shows numerous piles measured by the drone in one pit. ance and permitting. And compared to a WCB claim for a worker hurting their ankle, this is a good deal.

They have all the necessary permits to fly throughout Saskatchewan, excluding restricted airspace like near the Regina Airport and 15 Wing Moose Jaw. “It’s been great. It’s saved us so much time,” Swayze said.

“This is the future,” Didrick said.

“Because we have this system, we would have never tried to measure 200-some piles in one year.

Whereas now, we can do 207 flights a year. You saw that one pit, with 30 piles in one pit.”

Didrick said, “We also use it for drainage. It shoots

elevations. We don’t survey with it. We’re not surveyors by any means. But I’ve had people ask me to do drainage ditches so they can see where they need to take out (material) so they can drain to get their water off.

Plus, we’ve done dugouts.

It works great for dugouts, because it’s the reverse of a pile, right? To see how much clay they’ve taken out, we’ve done that too. It’s a busy tool.”

“We use it for pit planning. Before I bid a job, I can take this and we fly it and I can basically get the information we need to bid the job properly. Whereas before, you would drive in, look and guess. Now it’s more precise,” Swayze concluded.

PIPELINE NEWS July 2018

A19

Land sales bring in $15.6 million for Saskatchewan One lease parcel southeast of Radville brought in most of the bucks in the June 5 Crown land sale, whose results were posted on June 7.

One exploration licence in southeast Saskatchewan received a bonus bid of $10,511,566.

This parcel was purchased

by Stomp Energy Ltd. and is prospective for multiple targets including the Ratcliffe Beds of the Madison Group and the Bakken, Torquay, and Red River Formations.

The average price per hectare in Saskatchewan is currently $725, the highest when compared to public offerings held to date in Alberta and British Columbia, the provincial government noted.

“Industry’s investment in petroleum and natural gas rights in Saskatchewan is a good measure of the opportunity and potential that exists in our province’s oil and gas sector,” Energy and Resources Minister Bronwyn Eyre said in a press release on June 7.

“Dollars invested by this industry support Saskatchewan jobs, communities, and our province’s economic future.”

Forty parcels totalling 11,400 hectares were sold for $3,454,719 in the Kindersley area. These parcels are prospective for oil and gas in the Viking Formation, Mannville Group, and Bakken Formation. Cougar Creek Land Ltd. bid $608,948 to acquire a 243 hectare

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lease located south of Maidstone. This parcel is prospective for heavy oil in the Mannville Group.

The next public offering of petroleum and natural gas rights will be held on August 14, 2018.

Estevan-Weyburn area One single exploratory license offered in this area fetched $10,511,566, paid by Stomp Energy Ltd. It was for the 1,036 hectare block located adjacent to the Hoffer Ratcliffe Beds Oil Pool, 40 kilometers southeast of Radville.

This parcel is the highest dollar per hectare in this area at $10,146 per hectare.

There were seven leases posted and sold, totalling 648 hectares and bringing in $975,327, or $1,506 per hectare.

The top price paid for a single lease in this area was $600,087, paid by

Plunkett Resources Ltd. for a 130 hectare parcel situated five kilometres north of the Torquay Main Torquay Oil Pool, 40 kilometres west of Estevan.

Kindersley-Kerrobert area Two exploratory licenses were posted in this area and just one sold. It was for 518 hectares and brought in $213,307, or $412 per hectare.

Of the 51 leases posted, 39 sold, totalling 10,882 hectares. The bonus for the leases was $3,241,412, of $298 per hectare.

Top purchaser of acreage in this area was Saturn Oil and Gas Inc., who spent $768,896.83 to acquire nine lease parcels. In its own press release, Saturn noted the additional 6.75 sections brings their total land position to 24.25 sections

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(19.25 net).

The lone licence that sold in this area fetched $213,307, paid by Windfall Resources Ltd. for the 518 hectare block located 10 kilometres north of the Plenty Viking Sand Oil Pool, 35 kilometers east of Kerrobert.

Top price paid for a single lease in this area was $340,836 paid by Windfall Resources Ltd. for a 259 hectare parcel situated five kilometres southwest of the Forgan West Viking Sand Oil Pool, 20 kilometers south of Elrose.

This is the highest dollar per hectare in this area at $1,316 per hectare.

Swift Current area One singular lease was posted and sold in the Swift Current area. It was for 65 hectares and earned a $61,090 bonus, at $945 per hectare. It was acquired

by Scott Land & Lease Ltd. The parcel is located within the Gull Lake Basal Cantuar Sand Oil Pool, 5 kilometres southwest of the town of Gull Lake.

Lloydminster area The Lloydminster area saw only three leases

posted and sold, totally 583 hectares for $631,876.

That came to $1,084 per hectare.

Top purchaser of acreage in this area was Cougar Creek Land Ltd. who spent $608,948 to acquire one lease parcel, making it the top price paid for a single lease in this area.

The 242.81 hectare parcel is situated adjacent to the Soda Lake Cummings Oil Pool, 55 kilometers southeast of Lloydminster.

This is the highest dollar per hectare in this area at $2,508 per hectare.

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A20

PIPELINE NEWS July 2018

Dealing with people who just don’t want to see coal used in the future: Environment Minister Dustin Duncan

By Brian Zinchuk Estevan – Saskatchewan Environment Minister Dustin Duncan had a lot of interest with regards to his luncheon presentation on carbon taxation to the Estevan Chamber of Commerce on June 20. The question and answer period went just about as long as the 20 minute speech, as chamber members brought up numerous concerns, in a community that depends on coal mines and coalfired power for much of its livelihood.

Carbon dioxide emissions are very much on the mind of the provincial government, with the federal government threatening to impose a carbon tax, and an equivalency agreement which would recognize carbon capture implemented by SaskPower fleetwide, as opposed to individual generating units, still up in the air. Duncan noted, “It is no secret our government will soon have to make a decision on Boundary Dam 4 and 5.”

The carbon capture unit on Boundary Dam Unit 3 went into opera-

tion in 2014. The deadline for a decision on the next two units is fast approaching, and if they are kept in operation, there will be fines from the federal government.

Duncan said the decision on Units 4 and 5 would be made this summer.

“You no doubt know that natural gas prices are at historic lows. This makes natural gas an attractive, economical option for future power generation,” Duncan said. “So while we must take these costs into consideration, I assure you that we recognize the value of the coal industry in this community, and the contributions it makes to our economy.”

“That is why we are aggressively pursuing an equivalency agreement with the federal government, a federal government that has already decided that coal must be phased out by 2030,” the minister noted.

An equivalency agreement would give flexibility to keep Boundary Dam Units 4 and 5 operating,

otherwise, there would have to be a hard shutdown by the end of 2019.

Even if replaced by natural gas generation, that does not preclude the installation of carbon capture and storage on other facilities such as Shand Power Station. He noted that Shand’s lifespan is projected to 2042, and shutting it down in 2030 would make it a “stranded asset” that has already been paid for, but we could no longer use.

To date, he noted Boundary Dam Unit 3 has captured two million tonnes of carbon dioxide, the equivalent of taking a half million cars off the road.

Duncan said there were 1,600 coal-fired power plants in planning or construction phases around the world, and that China has added 600,000 megawatts of coal-fired power. In Vietnam, there is 4,300 megawatts of coalfired power being built; all new, all coal, “and none of it has CCS.” While Canada is on a track to eliminate coal-

Environment Minister Dustin Duncan addressed the Estevan Chamber of Commerce at the Southeast College Estevan campus on June 20. Photo

by Brian Zinchuk fired power, he pointed out we have no plans to ban the export of coal, and that last year we exported 36 million tonnes for power and steel production. Since west coast states have not allowed additional coal shipping, American coal is being exported via Vancouver.

Duncan said Canada is responsible for 1.6 per cent of global carbon dioxide emissions, and Saskatchewan is responsible

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for 10 per cent of that.

Reducing our 75 million tonnes of emissions per year to zero would have no impact.

He pointed out that with recent tax cuts in the United States, a carbon tax just might be the final push for competitive capital to go elsewhere.

With regards to a carbon tax on Saskatchewan, Duncan said, “They call it a revenue-neutral tax, an oxymoron if I’ve ever heard one.”

While the federal liberals have said agricultural will be exempt, it will still apply to fuel, and the natural gas used to make fertilizer.

He said the province is taking Ottawa to court on this, noting, “Ottawa is trying to impose this flawed policy on some provinces, but not others.

There will be no stopping the federal government at $50 per tonne.”

Duncan touted the Saskatchewan government’s “Prairie Resilience” plan to reduce emissions without a carbon tax, a plan to use green technology to

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get “real results,” with 11 million tonnes of actual reductions in emissions.

One of the questions from the floor was “What’s Plan B if we can’t get an equivalency agreement?”

Duncan responded that the agreement is taking longer than expected.

“The goal posts keep moving, from the federal government.”

“It’s frustrating to say the least.”

Even if they get an equivalency agreement and build carbon capture at a different facility, there is still the need to refurbish BD Units 4 and 5.

He noted the landscape has started to shift on the carbon tax, with Ontario now against it, and Alberta may have a change in government eventually.

“This has never really been about emissions,” Duncan said of the carbon tax, saying it was more about locking in policy decisions, regardless of the province.

He concluded saying, “We’re dealing with people who just don’t want to see coal used in the future.”

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