The Supply Side: Cracks showing?

IEA Revises Production Down for 2015

The IEA's revision of non-OPEC supply growth in January's Open Market Report hints at the supply side destruction I've speculated about previously.

While they point to a 175k bopd revision in Columbia, they also show a 95k bopd in the US and 80k bopd in Canada. The article speculates that price may not turn quickly, but these low prices aren't likely to achieve any sort of steady state equilibrium (emphasis is my own):

The most tangible price effects are on the supply front. Upstream spending plans have been the first casualty of the market's rout. Companies have been taking an axe to their budgets, postponing or cancelling new projects, while trying to squeeze the most out of producing fields. For the most part the supply effects will not be felt immediately, but further down the road, through project delays and faster decline rates. Nevertheless, expectations of non-OPEC supply growth for 2015 have already been downgraded, with growth for the year adjusted downwards by 350 kb/d since last month's Report and more steeply so for 2H15. Colombia and Canada lead the declines. Expectations of US light, tight oil production growth have also been revisited, but so far the cuts do not exceed 80 kb/d compared with our already conservative previous estimates, as many producers appear to be well hedged against short-term price drops. 

There's alot of meat in that, but I think this is a question of market interpretation. To me, when I read that, I see high cost oil as being the intuitive easy casualty. But with Canadian oil growth coming from the oil sands it merely gets pushed back a time period.

The light tight oil game is where the action will be. Production won't drop in the short term due to price hedging.Which makes sense. But what happens when those hedges need to be renewed? What happens when the financing used to drill the wells coming on line need to be re-upped on the next wells?

LTO Decline Rates

I keep harping on this, but it just seems like the story to me: faster decline rates. It's almost worth subscribing to these IEA reports just to get the more detailed version, but that's a huge differentiator.

Accepting the premise that the US LTO is the marginal barrel of oil (ie. that it's incredible production growth has largely led to the supply glut we're seeing) then the implication of it's behavior and sensitivity to these market conditions is paramount. Decline rates are important because they need to be replaced with new production before growth can occur. That LTO has achieved that so far is incredible. And according to my premise has been the most impactful development in terms of this supply glut/price gutting.

Market Implications

Remember, markets move on expectations. Sure, the current real time conditions (price obtained, quantity produced, etc.) matter, and arguably matter the most, in forming those expectations. But when these companies go to market for financing they will be faced with financiers concerned with the price obtained in the future and the quantity produced in the future. Both of which get murkier by the day. Uncertainty requires price premiums.

Remember, saying that someone is well hedged also means that someone hedged them unprofitably. Did they adequately price in the possibility of sub $50 oil when the contracts were written? I'm guessing they didn't. So if there were any wells deemed marginally economic with these contracts locking in the well hedged prices, they likely won't be any longer even if price rebounds to $100.

The players writing those hedges may exit the market altogether or they may re price those hedges. The point is that this past 6 months has to materially impact expectations (for the majority of us that didn't see sub-$50 oil coming), risk premiums, and general participation rates.

That is strictly on the hedging side. But the same applies to financing. What was the range of price used in sensitivity testing? My assumption is p ($50) last summer was tiny if even considered. Will it remain that way if oil prices rise back up to $100+ by this summer? There is no way. Again, as financing gets more expensive or dries up previously marginal economic wells aren't drilled.

Aggregate Impact

The physical properties of LTO being high initial production (IP) into a steep decline places a greater importance of these wells continuously being drilled. Aggregate production from a play depends on it, I've referred to this previously as the need to increasingly increase drilling activity. Particularly if you consider the creaming effect (cream rises to the top, top prospects are drilled first) and a maturing LTO play.

So again, if prices remain low I think we'll see the IEA consistently revise this US projection number down.

I look forward to next month to see if I'm full of shit or not!

A Follow Up On Supply Side Destruction

I posted here about how I believe markets will behave. My particular emphasis was on the precarious nature of the status quo. Namely, that it's unstable; because current output levels can not be maintained in this current price environment.

It seems to me that the Saudi's need to convince the market that their strategy is the new status quo. Period. We will produce oil if it's economical, our oil is economical down to $x, so good luck with your oil! Similar to forward guidance in monetary policy, the swing producer can only move markets with words if their actions (or more specifically, their communicated future actions) are deemed credible.

Arguments against the credibility of this new non-price supportive strategy seem to hinge on the 'break-even' fiscal story (which gets mentioned all the time and I largely ignore when it comes to KSA). However, in terms of sheer economics, market share, market power, geo-political and regional balances of power, alternative fuel viability, the KSA seems likely to pursue their market grab. At the very least we need to consider it credible until proven otherwise.

Implications of Lower Prices

Although we hear it discussed more and more, I still believe the heterogenous nature of oil market is underreported. First, defining oil is inherently difficult, what we call 'oil' is crude oil, the EIA summarizes the variety here where oil is classified according two qualitative variables: density (API) and sulfur content (sour/sweet). Sweet oil is good (less refining required to get useable product). Mid density is good (the heavier the oil the more 'energy' is contained in the carbon chain, it's a balance between energy content and difficulty in cracking it in the refining process).

The second differentiator is the price differential. In Canada we know all about this. These differentials are driven by the local quality of the oil, but also the ability of that oil to get to markets that want them. The EIA article above outlines that globally. In this article from Bloomberg describes inter-regional price differentials. Which is where things start to get a bit more interesting. First let me set this up a bit.

This article by Euan Mearns on Seeking Alpha points sketches out where the 'new oil' is coming from. Namely, Canada and the United States:

Figure 2 Global production of conventional crude oil and condensate has not changed since May 2005 despite a prolonged spell of record high oil price. All of the growth has come from expensive LTO and tar sands. The toxic mix of high debt and losses in the LTO industry that are in the making may short circuit the global banking system again.

Here, LTO refers to the Light Tight Oil that is typically referred to as shale oil (not to be confused with oil shale). This is the Bakken, The Eagle Ford, the multi-stage fracks, all that good stuff.

So that's the set up. Why these sources of oil have been prolific is something we'll skip over (how much is ingenuity, how much is the recent steady state of $100+ oil?). But where this gets interesting is when you consider the variation in production costs.

Prices and Production Costs

Again, this is an incredibly difficult figure to make sense of. These costs vary with the factors mentioned above. The regulatory and transportation frameworks are also key. But aggregated I think we can fairly make some interesting and relevant inferences.

Decline Rates: By definition, if decline rates increase, the number of new wells that need to be brought online to maintain production levels also increases. This isn't controversial. How quickly wells decline is another difficult thing to be accurate on, however, it isn't controversial to suggest that LTO wells have significantly higher decline rates.

It will be interesting to watch how oil sands and LTO production behave if oil prices continue to hover in this lower range for a significant portion of time. You'll see capex budgets slashed in Alberta, without any real production decline (rather a reduction in growth), but how will LTO production behave?

It will depend on the fiscal health of these companies and the duration of $70ish oil, but since LTO requires drilling activity to maintain production levels, and increased drilling activity to produce the production growth we've seen, any hiccup in capex will have a much larger impact then we'd see in any other oil play.

Costs vs. Prices: Let me butcher Econ 101 here: shut down isn't justified simply when operations are cashflow negative. Rather, you have to make a few considerations. The future behaviour of both costs and price. Costs have both a sunken and operating portion, where the sunken portion are more long run (infrastructure, regulatory, exploratory, etc.) and operating costs refer more to the actual production and transportation of oil to markets.

Again, with high decline rates comes more drilling, comes more regulatory issues, comes more infrastructure (increased production points). And these decisions happen in real time. Oil sands projects have massive upfront costs. They also have high operating costs (relatively speaking). The difference is in how the economics impact production volume.

LTO companies can immediately cut the sunken costs by reducing drilling activity. How long it takes to work through the backlog of well sites ready to go (with significant sunken costs) remains to be seen. But I have to believe that if low prices stretch through this drilling season into next year's drilling season, we're bound to find out.

Oilsands production might stagnate, but remember that massive upfront investment also results in fewer individual decisions.

Duration: Steep decline rates also mean that when a new LTO well is brought into production is more important to the lifecycle economics of the project. Rune Likvern has done alot of interesting work on decline rates and the subsequent economics. While, his overall production predictions have not come to fruition, the underlying logic still remains solid (in my eyes). In this follow up posted on Peak Oil Barrel, Rune makes some interesting points.

Most relevant here is the notion that the leverage that has enabled this massive drillout of the LTO plays in the United States are likely also conditional on the high price of oil. Now we have pressure from both the strict cost and benefit economics of the oil well, but also, the exogenously determined credit conditions. Being in the finance game I know that when some guy in some office some where gets freaked out about a negative trend, the tap can turn on and off pretty quick. Might the tap turn off quick here? It likely depends on the expected duration of these low oil prices.

Remember, LTO producers are firms, they have no access to printing presses. They dividend out their earnings. They are accountable to quarterly reports. They are not national oil producers. This makes for the most efficient model when it comes to exploiting economic plays. But when they become uneconomic? Well... we might just find out.

Conclusion

I believe we will see supply reduction and prices rebound. Over what time frame? No idea. But if the KSA won't take on the entire burden. The first domino to fall will be the US Shale producers. They've had the greatest impact on global oil production. But the nature of the oil production and the debt factor will necessitate blinking first.

Supply Side Destruction

As discussed here, OPEC's latest (last?) decision to not reduce production in order to arrest the recent fall in price, has lead to alot of speculation about what we're likely to see come out of this.

Now, I should start by confessing to being totally wrong on this type of occurance happening. While I'm not quite convinced that I need to scrap my overwall Peak Oil Dynamic world view (explained here), this certainly has caught me by surprise.

One of the key factors of the Peak Oil Dynamic world view was that the conventional cheap oil is shrinking both in aggregate and proportionally to expensive and/or unconventional sources. That logic led me to believe that the offshore oil market would be strong going forward and we'd see oscillating prices around that $100 mark for awhile but likely a steady secular rise in prices until someone figured out renewables.

Obviously, the oscillation didn't happen. Why? This is a supply side phenomenon.

From the IEA

Demand growth may not be as rapid, but it is still growing. And despite what all the hippies are saying, there is no viable replacement on the horizon.

So the collapse in price must be supply side.

Where that supply is coming from is interesting. I'd think about this 'new oil' in two seperate categories: expensive oil and cheap oil. Basically, expensive oil is the oil that was made available due to the $100+ price of oil (and SOME technological improvements, but don't kid yourself it was mostly the price), and the cheap oil is the production that is from conventional legacy sources that for political reasons have not operated at or near full capacity in some time. Think Libya, Iraq, Iran, etc.

Now, price certainly has an impact on cheap, politically sensitive oil production levels. But those effects are typical complex and to entangled in secondary and tertiary political/social/economic effects and so I will leave them be.

The more interesting of these two sub-sections of 'new oil', the expensive stuff, are where things will get interesting and where marginal barrells will be taken off the market if an exogenous supply reduction is not imposed.

In terms of simple Econ 101, suppliers will either make due at the lower price level, or we would expect the marginal producers (those requiring $70-$100+ oil to maintain operations) will drop off.

In oil's case, things are complicated by the wide divergence in a number of factors, a few of which are: 1). the sunk cost of different production methods, 2). the decline rates of different production methods, 3). what market the oil is sold into, 4). the firm's fiscal health, 5). the firm's hedging strategy.

Again, mix, oil, politics, and big business, and all you can do is make guesses. Popular opinion seems to be fairly mixed, with a number of folks suggesting that the wheels will fall off the shale boom and other suggesting they've all hedged out any risk.

This piece in the Telegraph has a few interesting items:

US producers have locked in higher prices through derivatives contracts. Noble Energy and Devon Energy have both hedged over three-quarters of their output for 2015. 

Pioneer Natural Resources said it has options through 2016 covering two- thirds of its likely production. “We can produce down to $50 a barrel,” said Harold Hamm, from Continental Resources. The International Energy Agency said most of North Dakota’s vast Bakken field “remains profitable at or below $42 per barrel. The break-even price in McKenzie County, the most productive county in the state, is only $28 per barrel.”

So those are the headline numbers, but this of course begs the questions: how do you determine the break even cost? Is that break even on existing production? Is that break-even to maintain current production levels? Is that break even to maintain current growth rates in production levels?

And all credit to this article for taking the time to wade into this discussion but I have to disagree with the following quote from Ed Morse at Citigroup:

Mr Morse says the “full cycle” cost for shale production is $70 to $80, but this includes the original land grab and infrastructure. “The remaining capex required to bring on an additional well is far lower, and could be as low as the high-$30s range,” he said. 

Critics of US shale may have misunderstood its economics. There is a fast decline in output from new wells but this is offset by a “long-tail phase” for a growing number of legacy wells. The Bakken field has already reached 1.1m bpd, and this is expected to double again over the next five years.

I don't believe we know too much about how these legacy wells will behave. Also, we need to remember that these growth rates, in the context of fast production decline, are necessarily the result of increased drilling.

Now, to maintain drilling, you need to maintain acerage and the expansion of infrastructure IF prices remain depressed beyond what drill sites have been allocated. Beyond that then the full cycle cost is back in play.

Another items to consider is that the best portions of an oil play typically get drilled up first. Of course, a play isn't known in it's entirety from the get go, but it's not unrealistic to expect that the 'sweet spots' are more likely have played a starring role in the ramp up in production.

Also, remember that when companies are talking about break even costs in the media they also have stock prices to maintain. Any highly leveraged play gets increasing leveraged when stock prices dip. That combined with a reduction in cash flow (even if most of it's hedged) is a dangerous game to play.

So you want to watch for a couple of items: a reduction in drilling activity and a reduction in the per well production rates.

This article in Reuters showed a reduction in drilling permits issued dropped over 40% in November, which is a bit of an eye opener. But to be honest with you, I don't have a clue about the typical fluctuations in permits so I took it with a grain of salt.

The author also cites Allen Gilmer at Drilling Info who suggested that this was mostly due to companies wishing to avoid tapping new sweet spots in this depressed price environment. So the exact opposite of what I said above.

Who the hell knows. But it should be interesting to watch.

Thinking About OPEC's Meeting

OPEC's meeting concluded with a resounding shrug of the shoulders. At the end of the day it was the Saudi's decision. I had suspicions that they'd communicate price support at some level; but in hindsight why would they? At the end of the day, I can't think of any particular self interested reason for them to do so.

The interesting thing about this meeting, and given the complexity of modern finance, I was curious to see how price would react to OPEC's (the Saudi's?) communication; and specifically so. Forward guidance, is pretty well understood to be the dominant tool of central banks.

When credibly made the bulk of a centrals banks adjustment is done by markets inline with their expectations. So, if a central bank continuously targets 2% inflation and continuously undershoots it. The market prices in the undershoot. If a central bank announces the injection of funds on a short term basis, the markets price this in and money neutrally basically holds.

Would the Saudi's be able to achieve price support, simply by communicating a target? Would the world believe them?

We certainly saw markets react to OPEC's shoulder shrug, WTI quickly shot from $74 USD down to about $66, similarly Brent plummeted from about $73 to $70.  And I suppose we'll never really know if it's reaction would have been symmetrical (asymmetrically interesting to me).

Why would the Saudi's enable OPEC?

Had the production cuts been proportionately felt across OPEC members, it might make sense. If Russia had indicated that they would also be willing to curtail production in pre-meeting talks, then it might have made sense. But if the Saudi's have to bear the entire burden, why would they?

Vox's Brad Plummer outlines this point here. The key is probably in this Reuters article linked to in this article describing who would be bearing the brunt of that production decline:

With world markets awash in oil, Saudi Arabia embarked on a strategy of defending prices, which at the time were largely set by exporters rather than the nascent futures market. The kingdom slashed its own output from more than 10 million barrels per day in 1980 to less than 2.5 million bpd in 1985-86. 

Other producers failed to follow suit, however, both within the Organization of the Petroleum Exporting Countries and among new petroleum powers such as Britain and Norway. Prices fell into a years-long slump, leading to 16 years of Saudi budget deficits that left the country deeply in debt.

Plummer also links to this often cited look at government budgetary break even price of oil for OPEC countries. I still see this as apples to oranges.

No only do I believe that the Saudi's along with the rest of the gulf states likely set budgets according to revenue more then they raise revenue according to their budget. But the ruling regime does not hold the tenuous position, politically or economically then the other major exporters (of course including Russia which is not in OPEC).

With both Russian and Mexican officials meeting with Venezuela and Saudi Arabia pre-OPEC this probably presented a crucial test of price support viability. Between Russia and the Saudi's a joint strategy, would have significant market power due to not just their high level of production (Russia at 10.5 mm/bopd and KSA at 11.6 mm/bopd) but also their relatively low consumption levels (Russia at 3.3 mm/bopd and KSA at 2.9 mm/bopd) in contrast with the USA who, despite a huge upswing in production remains a massive importer on global markets.  It's these net available exports that are the interesting barrels to me on the market place.

Russia's Part in all of This.

But it's hard to imagine Russia artificially reducing production (as opposed to some new projects becoming uneconomic at low price levels) with the sanction package biting down on the economy. This article estimates that effect of oil and sanctions at $90-100B and $40B respectively.

This could make for an interesting winter. As far as I can tell, besides an escalation of the war, Putin's only real leverage would be physically delivery (mutually destructive) and a huge stockpile of nuclear material and know how. That or Putin backs down physically and rhetorically.

Market Share... At Who's Expense?

With no price support OPEC (KSA) made a clear statement that it would let markets dictate things going forward. It was always a fractious bunch and with the only partner, with both the production levels and political leeway to do anything but maximize oil revenue (the Gulf Emeritus would have the ability, but not the gross quantities), unwilling to cut production. OPEC basically isn't.

As for the Saudi's motivation, it may be a fight for market share by way of undercutting the more expensive marginal barrels on the market. From OPEC's official release:

"world oil demand is forecast to increase during the year 2015, this will, yet again, be offset by the projected increase of 1.36 mb/d in non-OPEC supply.  The increase in oil and product stock levels in OECD countries, where days of forward cover are comfortably above the five-year average, coupled with the on-going rise in non-OECD inventories, are indications of an extremely well-supplied market."

If the Saudi's are going for market share the obvious play to target is the rapid build up in tight oil production in the US. Not only is it fairly expensive (estimates oscillate in aggregation, to say nothing of the wide variation in per well/per location costs) but it's also typified by relatively steep decline rates.

How This Might Impact The US

You have to remember that once the investment in discovery, drilling, and establishing the production infrastructure, not in maintaining existing infrastructure and production. With increasing decline rates on each well any interruption in those initial capital outlays result in a much steeper drop in oil production.

Tyler Cowen links to this article by William Watts on Marketwatch that makes an interesting point:

At the same time, analysts have also noted that for many shale producers, a large chunk of production costs - acquiring acreage, contracting wells, etc. - have already been spent. As a result, the more important figure might be "half-cycle" production costs which analysts at Citi last week pegged at between $37 to $45 a barrel"

Eric Lee who is one of the Citi analysts on the report in Platts:

a “full capex cycle” shale project might have a per barrel cost of $70/b or more, but one that is a “half cycle” project, where a lot of the costs are already sunk, could be down into the high 30’s. Overall his conclusion is that a $70 basis WTI price could slow the roughly 1-million b/d growth rate in shale by 25%. “It looks like you would need about a reduction in rigs of 40% to 50% to really flatten production growth, and to do that you’d need about $50 oil,” he said. Overall then, the impact of the price fall on US production growth will be “soft.” (Morse noted that Citi has not changed its robust projections for higher US output.) 

I couldn't find the Citi report. It would be interesting to see how they got to these numbers. But we'll have to settle with for the author's synopsis. I'd be pretty curious to see the timeframe the author is speaking of. Certainly that full capex cycle number increases in importance as time rolls.

Bottom Line

I effectively read this as OPEC being no more. If there was a deal to be made, it would have been made between Russia and the KSA. There's an alliance to watch for. Maybe not until sanctions end. Maybe if sanctions intensify. Maybe never.

The things I'll be watching beyond the price of oil: Russia/Euro sanction negotiations, Russia in the Middle East (and Iran), Chinese oil consumption.

Cold Shouldering Putin and Opec's Big Meeting

 

A couple of interesting developments over the weekend at the G20's in Brisbane with Putin bailing out early got me thinking about end goals and strategic thinking. Naturally, with thinking about Russia comes thinking about oil. With thinking about Oil comes thinking about the Saudi's and the up coming OPEC meeting.

G-20 

The interesting thing about all of this is trying to parse out the end goals of key players. So we'll start with the G-20 and work our way back. While everyone has basically condemned Russia's behaviour in Crimea and eastern Ukraine, Cameron, Abbot and my own Canada's Stephen Harper lined up to get their very public digs in. My question is why? Ok, maybe 'why' is the wrong question. These statements are meant to play to their domestic audience, to make everyone feel like they are doing their part, standing up to the bully, etc. etc.. I get that. But perhaps questioning what these types of statements might actually accomplish is appropriate.

Is Putin going to say: "oh I didn't realize Stephen Harper doesn't want me in the Ukraine... shit, get me a phone and we'll pull funding/troops/tanks/whatever out... my bad". Or do you think he's more likely to dig in? Putin remains popular, ibut that popularity is dropping according to numbers cited from Leada in this article which also shows that the average rating out of 10 given to Putin by Russians was 7.33 (this in a time of capital flight, economic sanctions, tanking crude prices, and invasion of a non-threatening neighbour). Might backing him in a corner, help him drum up domestic support the old fashioned nationalistic (ie. they are bullying Russia... and so we bomb) way? I don't know. And Putin probably doesn't either. But I wouldn't bet that he'd opt for a passive reaction to blustery headline grabbing. When his constituents are convinced his current path is a positive one.

Also remember, that although many of the big multi-natinoal companies have dollar denominated debt that sanctions will prevent being rolled over; they and Russia in totality itself aren't too bad on this front. Also remember that since the Ruble has tanked, and oil is priced in USD this acts as a slight mitigant to price declines domestically. 

This article from the telegraph gives us a great summary of events in this post (found after I started).

I think they overstate the case that the global economy needs Russia more then Russia needs the global economy. But there is truth in it. Especially as fall turns to winter and the importance of energy supplies grow. I think the EU is feeling a bit more confident in their position as Brent trades near 5 year lows. Is that sustainable?

A potentially interesting bit in this article is the discussion on how prepared Russia is to hunker down. Alluding to the national sacrifice historical narrative, it does seem like Putin has a better chance of talking his Russian electorate into a winter of sanctions then Merkel would have talking her's into a self imposed winter of intermittent supply or inflated prices on their natural gas. Should Putin decide to retaliate in this manner (notice that Merkel didn't work as hard as the leaders mentioned above to grab headlines while still maintaining a critical position).

Despite letting the Ruble float (and subsequently tank), Russia has significant reserves (over $400B USD) and was wise to not stand it's ground so early. It won't be a couple weeks or likely even a couple of months until economic pressure is so significant that Putin is forced into backing down. It may turn into a battle of popular political will between a sanctioning euro population and a sanctioned Russian population. Here's hoping it doesn't come to that.

OPEC

The 27th could be a watershed moment. Hopefully we get some clarity on the strategic vision of the organization, or more specifically, the Kingdom of Saudi Arabia going forward. While this article does a great job of outlining the challenges faced by each of the major oil exporting countries. I think it doesn't fairly capture KSA's position. This graph that it cites from the Economist is a nice visual summary:



Like Russia, KSA has significant reserves ($745B in Sept.) so a downturn can be weathered. But articles like these assume all budgets are made independent of revenue. That doesn't seem likely in all cases (particularly KSA), where it seems more likely that they say: "hey look at all this money we're going to have, lets spend a bunch of it".

One of Manifa's 27 Man Made Islands

At any rate, the Saudi's  legacy oil production is some of the cheapest in the world. The billion dollar question of course is what the composition of Saudi production is now, and will be going forward. By the end of this year Manifa is supposed to be producing 900,000 bopd. That's not nothing. The scale of the project, and subsequent cost might (must) impact cashflow considerations. If their production remains the cheapest in the world, they might just go for market share.

Conspiracy theories abound about the motivation behind the OPEC's willingness to crater the price of oil. It's certainly helping economies around the world, particularly a country like China where through their structural reform the addition of nearly (5.7 million bopd this October x $100 vs. $80) $100 million dollars daily has been great. From another angle, the western bloc of countries imposing sanctions on Russia couldn't have had the oil markets help them much more.

Regardless of whether they will enforce or lower the production quota, hopefully we get some direction. I suspect that markets will be on the move shortly after the Nov. 27th meeting. Similar to FED announcements I suspect forward guidance on price support would have a huge impact immediately. Perhaps there will be an asymmetrical move with the opposite announcement, but I also suspect the market is pricing in continued low prices.

We'll just have to wait and see.

The return of the Mackenzie Pipeline.

The truly northern northern pipeline route gained some publicity this week as a report from Canatec Associates (an arctic petroleum consultant) that was commissioned by the Albertan government last year and has just been released  (I believe found here).

I had wondered about this possibility back in December (here) after Bill C-15, which grants more control over these types of decisions to the NWT, passed. My belief was that with a strong resource development supporter at the helm, NWT would be much more likely to get pipelines through then BC; all else being equal. Of course, all else isn't equal, and that hasn't changed.

Here is the Financial Post story: Arctic Route for Alberta oil could trump stalled B.C. pipeline projects.

The board is appointed by the federal minister for Northern Affairs. The result is a far more streamlined approvals system that could well usher a new pipeline through in record time.
Following the release of the report, Northwest Territories Premier Bob McLeod said he was “heartened,” and that he’ll be meeting with his counterparts in Alberta to figure out the next steps.  

“We’ve always said that there are significant resources that have been stranded for 40 years and we’re not going to leave them stranded for another 40,” Mr. McLeod told the Financial Post.

I really believe the viability of the NWT assets, particularly the canol shale potential in the Central Mackenzie Valley will be the key to getting Alberta oil to Tuktoyaktuk. No one wants to simply be a transit point. Then again, without the Canol Shale development, the NWT will be in need of revenue.

And there hasn't really been alot of news on the Canol Shale this year. MGM which had explored the north in general and the Canol more specifically, was subsumed by parent company Paramount Resources after alot of money was sunk into the region with no production to show.

Outlined here, MGM president Henry Sykes talks about the region:

“Our experience has not been a positive one. Obviously we’ve spent hundreds of millions of dollars, drilled 11 wells and have nothing really to show for it today in terms of any cash flow-generating ability,” said Sykes, who predicted similar outcomes for other companies. 

“Until there’s infrastructure in the North, until people can see a clear path to investment and return on investment, I think you’re going to find activity is going to be delayed, if not eliminated altogether,” he said.

Sykes go on to state that they were sitting on billions of barrel of oil (I'm assuming that's the play at large and not MGM's holdings). The scale of which would be pretty solid motivation. However, having helmed a failed venture Sykes might be a bit bias on the potential (if only there was access to markets MGM would be kicking ass!).

At the end of the day it's good to get another viable pipeline option. The added length and variability in operating a year round facility that far north will add significantly to cost. However, one might argue that a more favorable political climate may offset that. Hopefully, the Canol will prove viable economically.

The Oil Kings: How the U.S., Iran, and Saudi Arabia Changed the Balance of Power in the Middle East

Economics of Oil Sands vs. American Light Tight Oil

A Scotiabank report has been making it's rounds lately (cited here and here). It's an interesting snippet of information which cites "examination of more then 50 plays across Canada and the United States" as it's data set. We don't get a look at the methodology, but the claims are as follows:

In Canada, an average WTI oil price of US$63-65 per barrel is required to yield a 9% after-tax return on ‘full-cycle’ costs for the oil plays shown on page 1 compared with close to US$72 in the United States (based on costs in the Fall of 2013).

Interestingly, the article points to the plateauing production in the Permian Basin is plateauing. And a weak December in the Bakken according to NDRC data as outlined here by Ron Patterson at peakoilbarrel. Of course a singe data point is simply a single data point. But it does raise some interesting pricing and production possibilities for the future.

Keystone XL: Final Supplemental Environmental Impact Statement (SEIS)

Photograph by Larry MacDougal, Canadian Press/AP

Well it's finally out.

Here's all you need to know: Obama now has his justification to approve the Keystone XL (the parameters of which I outlined here).

The Mackenzie Valley Pipeline: Will Bill C-15 Bring it back to life?

(from the website: www.internationalfrontier.com)

IEA's 2013 World Energy Outlook Summary

The IEA has published their 2013 World Energy Outlook and in it they raise some interesting issues going forward. Unfortunately, I don't have access to the full report (paywalled here). However, the Executive Summary does sketch out the main points.

All in all, the message is pretty similar to the world view encapsulated in the definition of the Peak Oil Dynamic (as I've described it) where the supply side (and falling demand in the developed world) faces significant challenges to maintain pace with the developing world's growing appetite for oil.

The centre of gravity of energy demand is switching decisively to the emerging economies, particularly China, India and the Middle East, which drive global energy use one-third higher.

Alberta Pipeline Overview

With Albertan refining capacity at less then 500,000 bopd and production averaging around 2.8 million bopd in 2012  the need for export capacity is obvious. The Canadian Association of Petroleum Producers (CAPP) is projecting that supply from Western Canada will increase to 4.85 million bopd in 2020 (from about 3.4 million bopd currently) and 6.7 million by 2030. With current pipeline take away capacity around 3.67 million bopd we will need to find other means of getting our oil to market. Currently, the rail by oil capacity is picking up, but for this post we'll focus on pipelines.

Drowning in Oil...

I don't really get articles like this. I've certainly seen alot worse, but my two main points of contention are: (1) OPEC has some reason to worry and (2) we are awash in oil. Now maybe I'm oversimplifying and misrepresenting the intent of the article, but I keep reading items that seem to assume, or at the very least imply these two items and again, I just don't really get it.

How equivalent is a barrel of oil equivalent?

I had always glanced over the term Barrel of Oil Equivalent (BOE), and just assumed that it was, well... the same thing (essentially) as a barrel of oil. But what exactly is it? I'm also going to touch on Oil being called Oil that kind of isn't really Oil.

Natural Gas described in terms of Barrel of Oil Equivalent:

Consider that the equivalency is often cited on a BTU basis where 5,800 cubic feet of natural gas is equivalent to 1 barrel of oil. Now consider that as of today, Henry Hub is $3.58 (per 1000 cubic feet). WTI is at $107.24. In energy equivalence terms Natural Gas is going for $20.76 and Oil for $107.24.

This distinction should draw an even closer look when considering non-conventional plays with significant gas production, since high initial production and rapidly decreasing production levels are typical. The well economics are such that the current spot price basically determines the Net Present Value (NPV) since the combination of discounting and the very high decline rates often render future production inconsequential in determining the profitability of the upfront costs.

Oil that isn't really oil, but is kind of like oil (condensates in this case):

Up until the divergence in price between Natural Gas and Oil, Natural Gas Liquids would often be reported simply as oil production, similar to condensates now. Of course, to my limited understanding, condensates are significantly more like oil in the sense that NGLs are derived off lease, where as condensates take liquid form at surface temperature and pressure (I'll have a post on this stuff later). Currently, condensates seem to be priced close enough to oil to render a breakout of the two production levels unwarranted. However...

In this article on the Motley Fool Peter Horn discusses a comment made by EOG's Chairman and CEO Mark Pappa in which he hints at a possible softening in the condensate market (relevant to the Eagle Ford tight oil play in Texas). Horn also attached the following figure from EOG's latest slide deck:


The key point here, assuming accuracy, is that acreage beyond EOG's is dominated by condensates. If a similar push was made to break out condensate production (as occurred for NGL) from oil production. I wonder what impact this would have on market sentiment. I'll have another post soon discussing tight oil production, the impact it is currently having and speculate about the impact it will have going forward. Calling Eagleford's condensate, condensate, rather then oil would certainly change a few headlines.

That's not necessarily a bad thing. As a freemarketeer at heart I don't subscribe to the doomsday scnerios that seem to pop up at the end of many Peak Oil (or climate change, or Quantitative Easing, etc., etc.) discussion. Solutions will figure themselves out. According to this Blatts summary of an ESAI study (paywalled):

But in the announcement of its release, ESAI says its estimate is that the output of NGLs — which it defines as  NGLs/LPGs, ethane, condensate and naphtha — will hit 29.7 million b/d in 2023. Taking out ethane, which ESAI does not classify as a liquid, supply of those categories will be 26.2 million b/d out of total supply just over 100 million b/d.

If we're going to satisfy the growing appetite for energy with fossil fuels, we're going to need all the liquids we can get. These lesser sources will be crucial.

Libya's Production Collapse

We're effectively seeing a shuttering of the Libyan oil industry. The end game remains to be seen. But it will be interesting to see how quickly, and by how much the other OPEC countries can ramp up production to offset this supply loss. According to the EIA Libya had averaged exports of 1.3 million bopd in 2012. With Reuters reporting expected current exports of 80,000 bopd equating to the removal of over 1.2 million bopd from the market (For reference: According to NDIC data the Bakken averaged production of 756,985 bopd).  Here is the latest. 


Libya Oil Output Drops to 150,000 bopd, Exports at 80,000 bopd (Rigzone):

TRIPOLI, Sept 4 (Reuters) – Libya's oil production has fallen further to around 150,000 barrels per day (bpd), lower than last week's official estimate of around 250,000 bpd, as protesters continue to cripple the sector, an National Oil Corp official said on Wednesday.

(Reuters) - The global oil market is well balanced and top exporter Saudi Arabia ready to supply whatever volume of crude is needed to meet demand, Saudi Oil Minister Ali al-Naimi said on Thursday.

"Our (OPEC) production last month was almost the same as a month before, only 100,000 barrels a day shortage. There is no effect whatsoever...we won't see a crisis."Saudi Arabia pumped a record 10.19 million barrels per day in August, an industry source told Reuters.

Libya still a bigger risk to oil than Syria: Credit Suisse (CNBC)

Brent crude futures surged to a six-month high on Tuesday, reflecting fears that punitive air strikes against Bashar Al-Assad's government may be days away after the regime allegedly used chemical weapons last week in an attack on a Damascus suburb.Syria was a secondary factor behind oil's surge yesterday, which Credit Suisse saw as chiefly driven by "the likely prolonged absence of more than 1.0 million barrels per day of Libyan oil exports."

I think this makes alot more sense to me. In a previous post I wondered about a premium that would price in the risk of a widening conflict in Syria. I posited that any material impact on global markets would require Iran not only injecting themselves in the conflict, but also throwing a hail marry at the Strait of Hormuz. The CNBC article above mentions the oil terminus of the 1 million bopd Baku-Tbilisi-Ceyhan pipeline in Ceyhan that runs 50 miles from the Syrian border as being a logical target of reprisal. But when it comes to impacting markets, the dominating factor must now be the real drop in Libya over the hypothetical impact of Syria.  

As far as future impact is concerned, we might just get a glimpse at the vaunted Saudi 'spare capacity'. If Libyan production remains at these levels for significant amount of time, the strategy and ability of the Saudi's to turn on the taps may be revealed.

How Much Oil Is Really There?

If you've ever wondered why the price of oil is so high, or why people like myself are even interested in the scarcity question when we see 2013 stories about the Wolfcamp play, or the oil in Coober Pedy, or like last year's Bazhenov shale oil play in Eastern Siberia you aren't alone. The logic would go, Saudi Arabia produces lots of oil, here are three plays with comparable amounts of oil as Saudi Arabia, therefore, we'll soon have three sources of production comparable to Saudi Arabia.

While this could be the jump off point to a number of different issues on why oil is not oil is not oil, I'm going to talk about some resource classification terms that get thrown around in the media without much dissection. When I'm unsure I usually refer back to this Society of Petroleum Engineers (SPE) document.

Oil Initially In Place (OIIP): OIIP, sometimes referred to as "total resources" or Petroleum Initially In Place (PIIP) is used to describe the total amount of oil in a reservoir. Since recovery rate varies with the viscosity of the oil (how the oil flows), permeability of the rocks (is the oil able to flow), and the drive rate (naturally or unnaturally occurring pressure that forces the oil towards the well) this number can mean next to nothing without knowing more about the geology and the type of oil to be produced.

Reserves: This is an important metric. Reserves basically entail how much of this oil we'll get to market. This should include: development over a reasonable time frame, feasible economics under reasonable assumptions, the ability to get the oil to market is reasonable, and the ability to develop the reserve from a legal perspective are adequately evaluated. Reserves are further classified into Proven Developed Producing (PDP) and Proven Undeveloped (PUD) holdings to signify what portion of the reserve has actually been produced.

Resources: Broken into contingent and prospective resources, the first refers to oil that can reasonably be expect to get to market at some point but can't right now, while the second can be reasonably assumed from other information about the trend to exist, but have yet to be discovered. There are a number of sub categories for resources but the important point is, this oil will not be getting to market as things currently stand.

Unrecoverable: This is the portion of OIIP that does not meet the previous classification standards. This is the stuff that we can't really plan around. Some portion of it may become producible as economics and/or technical circumstances change, but some may never be recovered due to physical/chemical constraints.

Estimated Ultimate Recovery (EUR): This term is also generally used to describe the cumulative total of produced oil, reserves and resources. Although I find this term to be pretty vague. Like an economics model we need to know what assumptions are required to get this number. For example an EUR without discussion of price assumptions shouldn't be taken too seriously. Of course, predicting the price of oil to generate these assumptions is a crapshoot as well.

A key point is that besides OIIP these numbers are not static (OIIP estimates can change, but the actual OIIP number in theory should be static). This illustration describes where these classifications sit in the development process.

My point more simply is this: google is your friend. If you're blown away by a new oil play, find the source that the news stories are quoting and dig through the terminology and assumptions. It might help illuminate whether or not we actually have a 'game changer' on our hands.

As basic as my knowledge is on this topic, it's often enough to read through most news stories. Is it the next big find? Maybe. But I won't get to excited until investment begins to match the hype. And I'll probably remain a skeptic until the oil starts flowing.

Supply Side: Global Oil Production

This post is meant to be a highlevel look at who is currently producing oil and will sketch out some areas that I will explore in this blog going forward.

Looking at April 2013 total liquids production data we can see that the US actually was the leading producer at over 12MM bpd. The Saudi Arabia (KSA) and Russia rounded out the top three. These have been the big three since oil took on it’s central importance in the 20^th century. The key trends to notice are the American upswing and the steady European Decline. We’ll have plenty of time to explore some production possibilities for all the major players.

An interesting comparison is this April 2013 graph of Crude and Condensate production (C+C). 

In this graph we actually see that Russia is producing at the highest C+C level with KSA, Africa both coming in at a higher production level then the US. I will have a post on terminology and the other liquids that create the large gap between C+C and Total Liquids.

To reprint this graph from a previous post I want to again stress the importance of the undulating plateau that we’ve been on for C+C since 2005 around the 75MM bpd mark; despite the price incentives. This is the stuff that matters, crude oil is what we’ve built our society and economies upon. A decline in its production may not necessarily result in a decline in overall liquids, but it would bring a sense of urgency to the POD analysis.

I will post on the different types of liquids that cause the diverging gap between C+C and Total Liquids production.

Exploring the following areas will be my area of interest for what I deem the supply side of the POD:

1. American Production: What impact will the 'unconventional resources' have on future production?

2. Saudi Arabia and Russia: Guessing at the health of their existing conventional resources and their potential for new sources of production.

3. Decline Rates: How are the new sources of oil production impacting the overall decline rate of producing sources? How will Enhanced Oil Recovery (EOR) methods, used to increase recovery rate and even prolong the plateau phase of a field ultimately impact the eventual decline rate?

4. Africa: What is the potential for new conventional resources on this continent? Exploration has been constrained more by political risk concerns then the lack of potential. Assuming, (and hoping!) that Africa can collectively stabilize and develop in the coming future, what is the potential for the world to gain some new conventional production from this region?

5. Pricing: How will these different scenarios impact pricing, and how will pricing impact these different scenarios.
6. Megaprojects: the importance of Giant Oilfields that are currently producing.