...........

[Deer Hunter]

Remember this piece of business?
Spend $9.3 billion to have a refinery worth $1.0 billion. Then commit provincial royalty volumes which may cost another $26 billion over 30 years?


http://www.nationalpost.com/north%20...938/story.html

North West Redwater Sturgeon Refinery investors seek an early exit: report

Geoffrey Morgan, Financial Post · Jun. 23, 2017 | Last Updated: Jun. 23, 2017 4:58 PM ET




CALGARY – The NWR Sturgeon Refinery Project may be nearing completion but the company that owns half the project already appears to be looking for an early exit.

Calgary-based North West Refining, which owns 50 per cent of the Sturgeon Refinery near Edmonton, has hired investment bankers and is looking for “liquidity alternatives,” according to AltaCorp Capital analyst Dirk Lever, citing the privately-owned company’s annual report which has not been made public. NWR did not respond to a request for comment.

NWR’s stake in the under-construction refinery is valued at $500 million, according to AltaCorp. Canada’s largest oil and gas producer Canadian Natural Resources Ltd. owns the other half of the project, putting the total value of the venture at $1 billion.
The company’s annual report states that it has “engaged an investment banking firm to advise us on the potential options for shareholders and to make recommendations to the board,” according to Lever who read the report. NWR’s major shareholders are Calgary’s NorthWest Capital, Longbow Capital and Toronto-based Northleaf Capital.

“I think it gets sold,” Lever said in an interview, adding the business and its tolling is uniquely structured like a midstream or pipeline operation rather than a downstream refinery.

Canadian Natural declined a request for comment on whether it would consider purchasing NWR’s half of the Sturgeon Refinery.

Though the North West Redwater Partnership is private, Lever has a $5 price target on the venture’s 187.2 million shares, but notes “for the right buyer, the price could be higher.”

The company’s earnings for 2018, when the Sturgeon Refinery begins operations, would total $37 million and rise to $215 million by 2020, according to AltaCorp estimates.

Lever expects a corporation interested in the after-tax cash flows and significant tax pools or a pension fund would be likely bidders for the stake.

The AltaCorp report also shows the capital cost of the 50,000-barrel-per-day Sturgeon Refinery have now climbed to $9.3 billion, from a previous estimate of $8.5 billion in 2014. Additional phases, which would add 100,000 bpd of refining capacity, have been proposed but not commissioned for construction.

“If you look over the last 30 years, refineries have been shutting down, they haven’t opened up,” Lever said, adding the Sturgeon Refinery will also be the first built under the public-private partnership model.

The Alberta government and Canadian Natural backstopped an $860 million subordinated debt loan to help finance the project and the province has agreed to supply the refinery with 37,500 barrels of bitumen per day, which it collects as royalty in kind from producers. The remainder of the project is funded through $6.35 billion in bonds and $1.77 billion in bank facilities.

The project has also attracted controversy for its high price tag and use of public royalty barrels. Former Alberta finance minister Ted Morton published a study in April 2015 that called it an “economic boondoggle with high risks for Alberta taxpayers.”

Morton said soaring project costs and liabilities for the government, which will pay $26 billion in processing payments over 30 years, would make it difficult for the province to break even on the project.
North West has previously said the refinery will produce only low-sulphur diesel fuel, not gasoline, so the spread between bitumen and diesel prices is expected to be wide enough for all parties to earn money through the project.

Financial Post

gmorgan@nationalpost.com
Twitter.com/geoffreymorgan

[79ford]

The article confuses the small portion with the whole portion of the project.

The sources of opposition to this project probably go back to the main players in the alberta fuels market. 40-50 thousand barrels of diesel per day is going to be a downer for esso, shell and petrocans grip on the alberta fuel oil market.


I think anyone who buys significant amounts of diesel will appreciate the supply boost. There has been alot of trouble finding diesel for alot of people/companies over the years.


People generally dont get refining when they say things like refineries have been shutting down etc. Those refineries were old and capacity expansion at other operations has picked up the difference and then some.

Like the esso refinery, yeah winnepeg, calgary shut down but strathcona was built and strathcona produces more than calgary and winnepeg combined.... also, since strathcona esso was built they have increased production by 50 000 barrels per day which is more than the capacity of Ioco which shuttered in the 90's.

Petrocan has gone from 14000 barrels/day in the 50's to 144 000 thousand barrels now.


It is silly to say companies dont invest in production increases and building new units/debottlenecking etc.



When alberta goes from a million to four million people in the last thirty years where do people think the fuel came from?lol capacity to create fuel has had to quadruple over the years. NWR is the answer to future diesel demand in alberta and the economic growth that depends on diesel.

[Deer Hunter]

There is no shortage of diesel in Alberta. Alberta is already a net exporter of diesel. Most of it going to the Pacific Northwest.
Changing bunker fuel rules in 2020 may be the only additional demand for diesel.

https://www.bloomberg.com/news/artic...ed-fuel-market

[79ford]

So what do these people suggest to do as an alternative to manufacturing 120$ barrels of diesel?

Deconstruct the refinery, then Sell bitumin at a loss for 32$ a barrel instead? Lol

[Deer Hunter]

If the 50% part owner wants out just months before completion, I suggest it's not far from being over before it's started

[79ford]

The refinery/upgrader is already built, it is already here, may aswell make the best of it and if you look at the fact CNRL/murray edwards is involved in the other half i am sure these guys will probably let the nwr guys concede their share for the right price

The down turn has proven the model of bitumin producing and upgrading vs just hewing the bitumin for dirt cheap.

[79ford]

Originally Posted by Deer Hunter

If the 50% part owner wants out just months before completion, I suggest it's not far from being over before it's started

I wouldnt call it wanting out, it is more the nwr guys not being able to hold their end of the bargain so they will probably end up selling their stake to cnrl or some one else at a discount because they can no longer meet their financial obligations.

[Deer Hunter]

It's small. Overspent. Behind schedule. Surplus of diesel around.
It won operate profitably in this environment. The government will step in when this refinery causes its 40$/bbl oil royalty volumes to be worthless. Or worse, cost us more money for every barrel ran through this refinery.

[79ford]

Originally Posted by Deer Hunter

It's small. Overspent. Behind schedule. Surplus of diesel around.
It won operate profitably in this environment. The government will step in when this refinery causes its 40$/bbl oil royalty volumes to be worthless. Or worse, cost us more money for every barrel ran through this refinery.

The refiner is guaranteed the 12$ processing fee per barrel for processing the bitumin which is what seems to be the minimum price spread between oil and bitumin. That is what the province is more or less on the hook for. The province gauranteeing this is what allowed northwest and cnrl to get this financed with debt that is on their own books.


When you consider diesel production is flat out even right now and the price is still higher than gasoline you can see there is demand for the product.

Northwest has to take bitumin which is worth 30$ per barrel currently and turn it ito diesel which is selling for 100$ per barrel-130$ per barrel. The diluent that is recovered from the bitumin can be resold for higher than wti prices per barrel and the naptha stream from hydroprocessing can be sold for diluent at a similar higher price than wti as diluent.

Since it takes a barrel of diluent to ship three barrels of bitumin almost a third of the recieved v volume will be recovered as diluent which can be resold for above wti pricing. That is usually a 20$ spread in price when diluent recovery costs about 7$ per barrel.

The project after wringing out diluent then processes the bitumin into diesel, vaccum gas oil and naptha.

Naptha can be sold as diluent for a decent price-usually above wti.

Diesel is well worth 100$ per barrel or more usually. Where there is diesel there is jet fuel in the future.

Other products like pitch and heavy oils can go to asphalt production somewhere.

Propane and butane etc can go right into adjacent facilitys or pipelines for marketing.

Think of northwest as a diluent recovery unit that makes diesel and diluent.... it is freakin brilliant assuming cnrl doesnt blow it up

[ESOXangler]

As a guy who is actually somewhat in the "know" on this subject, I have to say 79Ford is bang on! High five!

Anyways Some people would rather not actually understand the fundamentals and just act mental.

[Dean2]

79Ford

Thanks for the great write up/explanation on the refinery. That is the first time I have clearly understood what exactly this refinery makes and how they can expect to be profitable. Actually makes sense as a project the way you explain it. I have a lot of respect for Murray Edwards, have known him since he was just starting out, so figured if he was involved in owning half, there had to be pretty good economic upside.

[Big Grey Wolf]

79Ford, what a brilliant explanation of the economics and value adding to our Alberta bitumen. In addition we have had many tradesmen working through a major down turn in the Alberta economy. 79 Ford you are one of the wise ones on the AO forum, I will look forward to your posts in the future.

[Drewski Canuck]

The whole point of the Northwest "Upgrader", was that Houston refused to do Value Added refining in Alberta, and decided to take the CHEAP bitumen south of the Border so that the profits from the value added was taken in the US.

There was a considerable spread between WTI and our Bitumen then, and there still is today. That is why the Tidewater pipeline is so important. It gives an alternative market other than the US that simply rigs the pricing because they are the only refiners equipped to take and process our production.

The truth of the matter is that the US lost the heavy oil supply from Venezuela for political reasons, and they really NEEDED our feedstock for the Gulf of Mexico refineries. But why pay a reasonable price if you don't have to?

A lot of the US Companies who invested in the oilsands really got took to the cleaners by the boom of the 2000's, and cost overruns of 100 % was the norm. They want to get their money back, and they want to get it back in their jurisdiction. The price spread and refining in the US is how they are doing it.

As such, here we are. BUT Its relatively easy to ship Diesel by pipeline as opposed to Gasoline. The stuff will sell.

Its just that this refinery has been so poorly managed in all of its stops and starts since it was first proposed. It has a high investment cost that will take time to recover. But it is a CANADIAN company, and not a foreign company, so that is an economic benefit to Alberta and Canada.

It is also a show of resolve to Houston that we will not be held hostage on our resource development. Heck even Justin Trudeau has learned the value of an alternative market to the US.

Drewski

[Deer Hunter]

12$/bbl processing cost is a far cry from the 35$/bbl quoted here
https://www.albertaoilmagazine.com/2...finery-primer/

A Cautionary Tale on Refining for the Alberta Government

Alberta’s new government wants to see more refining done in-province, but as their predecessor’s experience with the Sturgeon upgrader shows, that’s far easier said than done

BY TED MORTON – July 31, 2015


In government policy, as in life, the path to hell is often paved with good intentions. And so it is with Alberta’s bitumen royalty-in-kind program, or BRIK. What started off as a low-cost, low-risk initiative to incentivize more upgrading of bitumen in Alberta has turned into the multibillion-dollar North West Sturgeon upgrader – a project that will leave Alberta taxpayers holding the bag if it doesn’t fly.

It began innocently in the first year of the Stelmach government. Oil prices were soaring. Billions of dollars were going into new oil sands production. But unless new upgraders were built in Alberta, the growing volumes of bitumen would all be shipped south. No one was going to invest billions of dollars in a standalone “merchant” upgrader in Alberta unless it came with an ironclad guarantee of at least a 30-year supply of bitumen. Enter BRIK.

First proposed in 2007, BRIK would require bitumen producers to give the government of Alberta a portion of their bitumen in lieu of paying royalties. Risk to the government would be minimal, since it was merely acting as a middleman – collecting bitumen from existing producers and selling it to new upgraders. Prior to the 2008 recession, BRIK appeared poised to achieve all these objectives. Five upgraders were being built or expanded and another six were planned. These projects would have added three million barrels a day of upgrading capacity – more than tripling the current capacity.

When the 2008 financial collapse hit, oil prices plunged and investment dried up. Only three of the five upgraders under construction in 2008 were completed, and five others were either canceled or postponed. BRIK by itself was not going to build any new upgraders.

Eager to keep one of the premier’s signature commitments, the Stelmach government proceeded to sweeten the deal to keep a remaining project afloat: North West Upgrading’s refinery in Sturgeon County. Under this new scenario, rather than simply selling the bitumen to North West, the province committed to retain ownership of the bitumen, pay North West a processing fee or “toll” for upgrading it, and then sell the upgraded product. Construction costs were now estimated to be $5.7 billion (up from $4 billion). Eighty per cent of the capital costs would be borrowed, with payment on these bonds effectively guaranteed by a new 30-year “take-or-pay” tolling contract. This new arrangement effectively transferred the market risk of upgrading to the government – a liability estimated to cost $19 billion in tolls over the 30-year contract.

The financial risk of upgrading depends on three factors: the capital cost of building the upgrader; the costs of operating it; and the “spread” between the price of bitumen and the price of the refined products. If your all-in upgrading costs are greater than the spread, you lose money. Capital construction costs are another risk variable. The higher the costs, the higher the processing toll. By 2011, capital costs for the North West upgrader were estimated at $5.7 billion, with a guarantee that any cost overruns above $6.5 billion could not be added to the processing toll. This cap on capital costs was confirmed in May 2013. Five months later, then-premier Alison Redford participated in the official groundbreaking ceremony. There were smiles all around.

Not so now. Two months later, the government announced that cost overruns had driven the total construction costs to $8.5 billion, and the expected completion date was extended 12 months to 2017. In addition, the province would now loan North West $300 million to help with interim financing. The original $6.5-billion cap was nowhere mentioned. What would this 50 per cent cost increase mean for the government of Alberta’s toll payments? The province is now on the hook for $26 billion in processing payments – up from $19 billion – which translates into a processing cost of $35 a barrel, making it even less likely that the investment will break even.[/

Such projects tend to be motivated more by politics than by economics. Unequal expertise means that governments are often out-negotiated. Alberta’s new premier and any successors should think long and hard before falling for the next version of the diversification siren song of “refine it where you mine it.”

[Deer Hunter]

The cost to build this refinery is outrageous.

https://www.albertaoilmagazine.com/2...finery-primer/

The Sturgeon Refinery and the High Cost of Value-Added

Unexpected costs are eating away at potential returns for the Sturgeon Refinery. So why is it still being built?

BY GEOFFREY MORGAN – November 18, 2014


The Sturgeon Refinery is setting new records. It’s the first new refinery to be built with a carbon capture and storage system. It’s the first new refinery to be built in Canada in 30 years. It’s also among the most expensive refineries on a per-barrel basis to be built in the world.

“Nobody wanted to see the project costs rise.”

Consider that the 400,000-barrel-per-day SATORP heavy oil refinery in Saudi Arabia, for example, was built at a cost of $14 billion by Total SA and Saudi Aramco. On a unit basis, the project costs for that greenfield refinery build amount to $35,000 per barrel of new capacity. Project costs for the 230,000 bpd, $18.5-billion Abreu e Lima heavy oil refinery in Brazil, meanwhile, break down to $80,434 per barrel.

In Alberta, costs are much higher. The most recent cost estimates for the 50,000 bpd Sturgeon refinery put the price tag for the project at $8.5 billion – or $170,000 per barrel of new capacity. That puts the per barrel cost of the Sturgeon refinery at more than double the per-barrel cost of Abreu e Lima and nearly five times that of SATORP.

What makes refining Canadian heavy crude so expensive? Unlike greenfield heavy oil refinery builds in Brazil and Saudi Arabia, the Sturgeon refinery will process bitumen into diesel fuel, which means that a petroleum coker is required to upgrade the raw product before it can be made into diesel. The Sturgeon refinery will include a carbon capture and storage system, further driving up the price. It is also being built in a region with under four per cent unemployment. All of these factors carve away at the returns originally expected by the refinery’s proponents. Still, those proponents, being the government of Alberta, Canadian Natural Resources Ltd. and North West Upgrading Inc., are pushing forward with one of the most expensive refineries on a per-barrel basis to be built in the country’s history.




A groundbreaking ceremony was held north of Edmonton on September 20, 2013, to herald construction starting on the Sturgeon refinery, a project jointly owned by North West Upgrading and CNRL, and supported by commitments from the province of Alberta and CNRL to process bitumen at the facility when complete. Two months later, the project proponents announced Sturgeon’s expected total capital costs would rise from $5.7 billion to $8.5 billion and its startup date was also revised from mid-2016 to September 2017.

Then in June 2014, when Alberta’s provincial department of energy released its annual report, the public learned (on the final page of the 140-page document) that the fees the government would pay to the Northwest Redwater Partnership would jump from an average of $46.27 per barrel to $63.32 per barrel. Over the life of the project, that means the amount the government will pay increased from $19 billion to $26 billion over 30 years. By that time, the province and CNRL had taken out $300-million loans to provide North West Upgrading with subordinated debt financing to assist the company in raising the rest of the capital required to build the now $8.5-billion project. Providing subordinate debt to the project also gave the provincial government, through its newly created Alberta Petroleum Marketing Commission, equity in the refinery. “While the subordinated debt is outstanding, the APMC will hold a 25 per cent voting right on certain elements of the refinery’s construction and operation,” reads a press release announcing the refinery’s cost *estimate revisions.

In a March 2013 report called Extracting Economic Value From the Canadian Oil Sands, researchers at IHS CERA write that prior to the global recession of 2008, “Oil sands companies were gearing up to spend US$100 billion on oil sands processing facilities in Alberta.” The Sturgeon refinery is the only one of those facilities that has not been canceled or delayed. “A key risk with any new refinery investment in North America is the flat to declining demand for refined products in the continent,” the report states.

Asked why the government had recommitted to the Sturgeon *refinery project after the cost and processing fee revisions, former *Alberta *Energy Minister Diana McQueen says that the Sturgeon *refinery adds value to Alberta’s resources, will reduce volume on the province’s already strained pipeline infrastructure network, will *capture 1.2 *million tons of carbon annually and will earn an anticipated return for the province of between $200 million and $700 million. *“Nobody wanted to see the project costs rise,” she says, but adds the benefits still outweigh the costs.

There will be a further benefit to the province, says APMC CEO Richard Masson, because the Sturgeon refinery will take 78,000 barrels of diluent per day off the pipeline network running through the province, thereby freeing up space for more Albertan crude to reach export markets. He says the mandate of the APMC is to support projects that help earn the highest return for Alberta’s resources. To that end, the commission has committed 100,000 of Alberta’s royalty barrels to

TransCanada Corp.’s Energy East project. Interestingly, however, the APMC will leave the marketing of its diesel fuel to North West Upgrading after its barrels of royalty bitumen have been upgraded and refined.

To some observers, the Sturgeon refinery’s returns are too small to justify the government’s investment in the project. University of *Alberta economics professor Andrew Leach took his criticisms to *Twitter when the government revealed it would pay $26 billion in total processing fees at the Sturgeon refinery. Why, he asked, why not *purchase an existing refinery, perhaps on the U.S. Gulf Coast, and reconfigure it to handle oil sands bitumen at a much lower cost than building a new and much smaller refinery? Wouldn’t that earn the province a better return for its barrels of royalty bitumen?

In recent years, state-owned enterprises in heavy oil producing nations have taken precisely this tack. In addition to building the Abreu e Lima refinery in Brazil, Petroleo Brasileiro SA (Petrobras) spent US$1.2 billion to acquire Pasadena Refining System Inc. and its 100,000 bpd Texas refinery – meaning that Petrobras paid $12,000 per barrel of new capacity for its refinery in Texas. That’s roughly seven per cent of the per-barrel cost of the Sturgeon refinery. Even if a coker were added to a refinery like the one in Pasadena, the total project cost still wouldn’t come close to the cost of Sturgeon.

David McColl, a native Calgarian who’s now an analyst with Morningstar Equity Research in Chicago, says that before PetroCanada was acquired by Suncor Energy Inc., it estimated the cost of adding 40,000 bpd of coking capacity to its Montreal refinery. Adjusted for inflation, McColl says the costs would have come to $1 billion, or $20,000 to $30,000 per barrel. He does point out, however, that such an investment would be on a brownfield site, rather than a new refinery like Sturgeon. He also says that cheaper labor is available in Montreal, where companies don’t need to compete for skilled workers in the same way that they do in Alberta’s oilfield construction labor market.

It’s difficult to find a close comparable to the Sturgeon refinery in terms of cost. McColl says *CNRL’s other major downstream project, the *Horizon upgrader, which is integrated with its mine, was built at a cost of about $100,000 per barrel of capacity. A closer comparable might be Shell Canada Ltd.’s Scotford facility, which McColl says was built to upgrade bitumen at a cost of $140,000 per barrel of capacity. That project, he points out, is also being retrofitted with a $1.35-billion carbon capture and storage project called Quest, which is partly funded by the Canadian and Albertan governments for $120 million and $745 million, respectively. When complete in 2015, Quest is expected to capture 1.2 million tons of CO2 per year.

Like Quest, the CCS component of the Sturgeon refinery is expected to capture 1.2 million tons of CO2 per year, but a breakdown of construction costs on the project is not publicly available. McQueen says the Alberta government is supporting the CCS component at Sturgeon with $495 million in funding for the Alberta Carbon Trunk Line, which is tying into the refinery. The federal government is also supplying $63 million to that project. It is not clear, however, whether there are additional costs to North West Upgrading for installing CCS systems that tie into the carbon trunk line. If costs are indeed comparable to those of the Quest project, then it’s possible that the CCS component of Sturgeon accounts for $1.3 billion worth of the $8.5 billion capital costs. If so, stripping those CCS costs out of Sturgeon’s total capital costs would bring the per-barrel capital costs of the project down to $144,000 per barrel.


Purchasing an existing, out-of-province refinery and retrofitting it with coking capacity, however, was not a political decision the province was prepared to make. McQueen says the government recommitted to the Sturgeon refinery because it will take 78,000 barrels of diluent off the existing pipeline system on a daily basis, allowing local producers to get more value for their bitumen at home and abroad, which will in turn improve the royalties Alberta collects on those barrels. Reached for comment, outgoing NDP leader Brian Mason says, “We wouldn’t want [projects] built out of province.” Members of the Legislative Assembly for the Wildrose Party did not respond to requests for comment on the issue.

Though the Sturgeon refinery’s project costs are in the ballpark for a bitumen refinery built in Alberta, the sky-high costs of upgrading and refining bitumen in Canada draw incredulous remarks from industry players and analysts who work outside the Western Canadian Sedimentary Basin. Petrobras was widely criticized in Brazil for overpaying for its 100,000 bpd Pasadena, Texas, refinery, which was bought for $1.2 billion.

When asked how the Sturgeon refinery’s costs compared with other downstream projects around the world, New York-based analyst with the Cowen Group Sam Margolin couldn’t quite believe his ears.

He asked, “Are you sure it’s not a 500,000-barrel-per-day-refinery?”

Despite acknowledging that refineries processing bitumen are inherently more expensive that refineries that process light oil, he adds that, “On a per-barrel basis, [the costs] are pretty high.”

[Deer Hunter]

http://www.energy.alberta.ca/Org/Pub...ons/AR2016.pdf

Under the processing agreement, the Commission is obligated to pay a monthly toll comprised of: senior
debt; operating; class A subordinated debt; equity; and incentive fees on 37,500 barrels per day of bitumen
(75% of the project’s feedstock) for 30 years. The toll includes flow through costs as well as costs related to
facility construction, estimated to be $8.5 billion. The Commission has very restricted rights to terminate the
agreement, and if it is terminated the Commission remains obligated to pay its share of the senior secured
debt component of the toll incurred to date. The term of the commitment begins upon the commencement of
commercial operations. No amounts have been paid under this agreement to date.
The nominal tolls under the processing agreement, assuming an $8.5 billion Facility Capital Cost, market
interest rates and 2% operating cost inflation rate, are estimated above. The total estimated tolls have been
reduced by $1.26 billion relative to March 2015, due primarily to lower debt tolls. As at March 31, 2016 NWRP
has issued $3.65 billion in bonds at lower than anticipated rates and expects future bond offerings to continue
this trend.
No value has been ascribed to the anticipated refining profits available to APMC over the term of the agreement.
(b) North West Redwater Partnership Monthly Toll Commitment
The Commission has used judgment to estimate the toll commitments. The components of the toll are:
senior debt; operating costs; class A subordinated debt; equity; and incentive fees. To calculate the toll,
management has used estimates for factors including future interest rates, operating costs, oil prices (WTI and
light/heavy differentials), refined product prices, gas prices and foreign exchange.
The future toll commitments are estimated to be:
2016-17 $ -
2017-18 $ 261,000
2018-19 $ 656,000
2019 -20 $ 763,000
2020-21 $ 904,000
Beyond March 2021 $ 22,166,000

^^^These numbers are in millions of dollars per year
At 37,500 bbls/d which is the committed govt royalty volumes
The fees are
2017-18 $19.06/bbl
2018-19 $47.92/bbl
2019-20 $55.74/bbl
2020-21 $66.05/bbl

[79ford]

Originally Posted by Deer Hunter

12$/bbl processing cost is a far cry from the 35$/bbl quoted here
https://www.albertaoilmagazine.com/2...finery-primer/

Processing a barrel of diesel runs 40$ish. That is pretty normal that is why diesel is worth 100+ per barrel or more usually.

The major value add in refining is the shear amount of effort that goes into what some one thinks is a simple barrel of diesel or gasoline.

Oil refiners pump more money into the local economy to process each barrel of fuel than they spend on the feed stock.

Oil refiner pumps 50$ into the oil producer for the resource, the refiner then spends money on buying natural gas for furnaces, buying hydrogen from a nearby facility to hydroprocess the fuel, buying parts, maintenance, inspections, truckers haul and trains pull the fuel, operators and teams of engineers keep the plant running.

When some one says it costs 40$ to process a barrel into fuel all that money is going into the area around that refinery.

So instead of selling a 30$ barrel of bitumin to china with a third of a barrel of valuable diluent in it for a grand total of 30$ added to the alberta economy for one barrel....

A refinery in alberta plugs thirty 30$ in for the barrel, spends another 40$ converting it, then sells it for 100$ or more and spends alot of that revenue on maintenance and labour, parts, supplies, additives etc.

Why do you think edmonton is always ticking along? We got 460 000 barrels of refining capacity plugging 90$ or more per barrel into the local alberta economy.

Refiners make maybe 10- 20 cents a liter on the upper end, the rest of that money....alll that fuel being burnt in western canada is getting slugged into processing the stuff. Thats wages, pumps, valves, inspections, engineering, quality control, manufacturing, transporting 460 000 barrels of fuel per day to everyone who burns fuel. Which is pretty much everyone.

What do you think the guys down in texas are doing with our oil? They are refining the resource to make money, we can do that in alberta too.

No one burns bitumin in their car, every barrel out there is getting refined and some one is benefiting on that end.

[J0HN_R1]

Originally Posted by 79ford

...because they can no longer meet their financial obligations.

That was my first thought. Sounds like they're running out of money !

[79ford]

Originally Posted by J0HN_R1

That was my first thought. Sounds like they're running out of money !

The nwr portion of the parnership has been alittle light in the boots on money for some time now. The project has been started and delayed enough to wipe out pretty much everyone besides larger players. CNRL will probably get a good deal on nw's ownership share and make good on that.

This thing lime every other project in alberta that was a product of the boom times is not cheap what so ever. But these things like fort hills, kearl lake, horizon, northwest, shell scotford will run for decades and pile billions and billions into alberta while employing thousands of workers making six figure incomes for decades.

People always talk about how hard it is to get bitumin shipped because no one likes a pipe full of tarsands in their back yard.... probably alittle tougher to say no when the pipe is full of diesel. It is easy to say no to tarsands goes to china through a pipe, diesel is alittle tougher to say no, or gasoline. Diesel and gasoline are pretty familiar products to most people, everyone loves diesel and gasoline.

[HyperMOA]

Hey 79ford, I have a question for you. Its something I have wondered for a while now.

Even with production increases in diesel, do you think diesel will ever really be cheaper than gasoline in the future? I realize that we have faced shortages of diesel here raising the prices, but I had always assumed that diesel had stayed more expensive because the refining has gotten more expensive. Back in the 90s gas was 50ish cents and diesel was 35ish cents. Now with the ultra low sulphur content to meet Tier 4 Final emissions laws, I always assumed that the refining costs had increased the cost of diesel. Do you think the prices will ever correct to the point that where diesel will have an economic edge over gas?

Sorry for the derail.

[79ford]

Originally Posted by HyperMOA

Hey 79ford, I have a question for you. Its something I have wondered for a while now.

Even with production increases in diesel, do you think diesel will ever really be cheaper than gasoline in the future? I realize that we have faced shortages of diesel here raising the prices, but I had always assumed that diesel had stayed more expensive because the refining has gotten more expensive. Back in the 90s gas was 50ish cents and diesel was 35ish cents. Now with the ultra low sulphur content to meet Tier 4 Final emissions laws, I always assumed that the refining costs had increased the cost of diesel. Do you think the prices will ever correct to the point that where diesel will have an economic edge over gas?

Sorry for the derail.

If north west runs good and produces 50 000 barrels of diesel the price should become more normal. They will produce almost as much diesel as the imperial oil refinery does which is the largest refinery in alberta/western canada.

The biggest opponents to this are probably, imperial oil, suncor, and shell.... they have had diesel cornered for over a decade, they all produce at max rates as far as I know. I used to hate getting diesel when i worked out in the bush.diesel is a source of pain for many owners of equipment or trucks etc.

[Deer Hunter]

The price of diesel in Edmonton is one of the cheapest in Canada. Wholesale at $0.53/L
Or $84.50/bbl
http://www.petro-canada.ca/en/rack-p...k-pricing.aspx

Reg gasoline is the same wholesale price.

[HyperMOA]

Originally Posted by 79ford

If north west runs good and produces 50 000 barrels of diesel the price should become more normal. They will produce almost as much diesel as the imperial oil refinery does which is the largest refinery in alberta/western canada.

The biggest opponents to this are probably, imperial oil, suncor, and shell.... they have had diesel cornered for over a decade, they all produce at max rates as far as I know. I used to hate getting diesel when i worked out in the bush.diesel is a source of pain for many owners of equipment or trucks etc.

By normal do you mean the same price as gas, or do you think diesel will be 20%ish cheaper than gas? Diesel must be more expensive to produce today than it was in the 90's if we calculated inflation out of the equation. It was a much cruder fuel 25 years ago. Would you agree?

I think at best diesel will only be on par or near par to gasoline. I just don't see a 25% savings on a fuel which produces more BTU's ever again. That alone is why I don't own a diesel, yet make my living working on diesels.

[Big Grey Wolf]

The actual retail price of a 45 gal barrel of diesel is $200, not a bad Value Add, take a $20 barrel of bitumen and make it worth 10 fold and create a whole bunch of jobs in Alberta rather than Gulf in US.

[Deer Hunter]

Don't confuse retail pricing for fuel versus what the refinery gets paid for it.
Wholesale refinery pricing for diesel is 0.53/L or $84/bbl

For a 26 billion dollar commitment, the government could give 11,000 people jobs for 30 years at $80,000/year per person

And still sell their royalty volumes as positive cashflow