Canada O&G Outlook 2011: Oil Sands ready for PF debt?

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Canadian Oil & Gas Outlook 2011: Oil sands ready for PF

debt?

Gaurav Sharma

06/06/2011

Calgary (IJ online)–

The existence of oil sands and the bituminous crude theycontain has been known for almost 70 years but it is in the last 20 that oil and gas

infrastructure project sponsors, financiers and technical advisers have made

meaningful moves to tap the resource. One market stands out – think oil sands,

think Alberta, Canada.

The country‟s western provinces, Northwest Territories and Atlantic Canada have always been

developed markets for energy projects, but something of a sea change took place in 2006

when oil sands production first surpassed conventional production. The response of the

financial community to providing the debt for these projects has been mixed and the global

financial crisis complicated matters further.

IJ‟s research on the ground suggests a mature Canadian energy project finance market is

reshaping itself. The case could be a convincing one for a multitude of reasons and regions

from the unconventional bituminous reserves to Bakken oil formation in Saskatchewan and

the Cardium oil formation in Alberta.

That is not forgetting that Atlantic Canada still provides 10 per cent of Canadian production

according to latest figures[1]. Additionally, Canada also has 550 trillion cubic feet (tcf) of shale

gas

[2]

and by 2035, the US EIA projects Canadian shale gas production could reach 5 billioncubic feet (bcf) per day.




Ongoing mining work at the Athabasca Oil Sands, Alberta, Canada © Royal Dutch Shell

In the energy business, project financiers rarely get excited without a resource rich reason.

Independent industry estimates suggest Canada‟s oil reserves range from 173 to 175 billion

barrels of the crude stuff [3] and that is reason enough for most. Even the lower end of the

estimate makes them the second largest reserves in the world after Saudi Arabia. In order to

reach these barrels, the oil sand needs to be mined, crushed and diluted to release the

bitumen and mining presently accounts for just over half of the production.

A quantum leap is required between getting the bitumen out of the Canadian soil andconverting it into gasoline for use in Dublin or Delhi – no one denies that and almost all oil

majors believe the promise the sands hold. Proof of that lies in the fact that not a single one

of the top ten major multinational oil companies by market valuation has chosen to ignore

the oil sands let alone their Canadian counterparts.

PF data & something about “Oil sands” not “Tar sands”

Call them “tar sands” and not “oil sands” and Canadian energy professionals are not the only

ones who go all squeamish. While Canada has the largest resource, US, Venezuela, Russia

(FR Tatarstan and Eastern Siberia), Congo and Madagascar also have the resource in

appreciable quantities and others are looking for it where prospection possibilities exist.

However, Canada in general and Alberta in particular are the flag-bearers of what is

described by petroleum economists as the “unconventional” oil age.

The IEA more or less acknowledged the description when it noted that conventional global

production, i.e. easily recoverable using drillbits and at shallow depth is nearing or is already

at its peak. Simply put, bituminous crude (along with deepwater drilling) must fill a supply

gap which is not here yet, but may be around the corner.




Alberta is certainly taking the challenge seriously. The Canadian Association of Petroleum

Producers (CAPP) told IJ that over 2011 alone, project developers will spend CAD$15 billion

(US$15.33 billion). The big question is how much of the stated figure would form the equity

basis of projects, for which the debt markets would be approached. IJ‟s PF data specific to oil

sands project development reflects more than a strong fluctuation in terms of transaction

volumes courtesy of the global financial crisis which made some of the oil sands project

development unfeasible; albeit temporarily as it has turned out.

Canadian Oil & Gas Project Finance Valuation (Click to enlarge) © Infrastructure Journal

From project debt financed developments valued at a mere US$50 million in 2005, the

valuation spiked to US$5.3 billion in 2006; the year unconventional production overtook

conventional production in Canada. However, since then the valuation figure has fluctuated

wildly dipping to US$795 million in 2008 but rising to US$2.42 billion the following year.

Within this dataset, IJ records suggest oil sands, conventional and gas project sub-segments

with the highest valuation for which PF debt was sought are as follows:

Unconventional: Long Lake Oil Sands Project Refinancing – Financial Close: Dec 2006,

US$1.44 billion [Projects Database]

Conventional: Seadrill Drilling Units Acquisition Refinancing – Financial Close: Jun 2009,

US$1.5 billion [Projects Database] Gas: Canaport LNG Terminal – Financial Close: Nov 2006, US$ 1.1 billion [Projects

Database]

The McKay Oil Sands Phase I [Projects Database] valued at US$148.5 million is the latest PF

development site to reach financial close in December 2010. Overall financing for oil and gas

projects, which includes projects where the debt markets were not approached, remained

relatively stable more so because sponsors did not feel it was worthwhile to approach the

debt markets as there was a question mark over feasibility of the projects, local taxation

issues in Alberta and 2007-08 saw extreme crude price volatility from record highs to record

lows over a period of six fiscal quarters.

http://www.ijonline.com/GenV2/ProjectDatabaseV2/DisplayProject.aspx?TransactionID=10319












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Between, 2004 and 2010, analysts at Sayer Energy Advisors recorded total commercial debt

peaking at CAD$13.5 billion (US$13.75 billion at December 31, 2007 exchange rate) in 2007

backed-up by CAD$12.05 billion on the equity side. Over 2008 and 2009, the commercial

debt and equity ratio remained near similar but in 2010 the debt level plummeted to CAD$6.2

billion (US$6.19 billion at December 31, 2010 exchange rate) while invested equity rose to

CAD$13.74 billion[4].

Canadian Oil & Gas Industry Financings (All figures in CAD$, Click to enlarge) © Sayer Energy Advisors

Looking ahead to the period from 2011 to 2015, different dynamics are at play here and debt

financiers should greet the next five years with cautious optimism, according to Dave Collyer,

President of CAPP.

“Circumstantially, most of the financing to date has been equity financed. I think as we get a

more diverse mix of companies involved in oil sands and that is increasingly happening – this

will change. Around 80 per cent of the resource is amenable to in-situ (techniques which

apply heat or solvents to heavy oil or bitumen reservoirs) and 20 per cent to mining. At this

point majority of the production is from mining projects but increasingly over time we will see

that the produce would come via in-situ projects which are by definition smaller projects than

some of the mining projects,” Collyer told IJ in an exclusive interview.

In-situ investment as opposed to mining is of a smaller scale in relative terms, is

compartmentalised and contains a series of project facets which link-up and follow on from

one another.

“We see it as a type of investment which lends itself to smaller and intermediate companies –

who by definition have a smaller capital structure or different capital structure to the large

firms. So this mix is crucial to how projects will be financed over time. As the oil sands

business becomes more mainstream and more accepted in terms of growth opportunities and

the risk profile - then we will see a mix of financing going forward,” he adds.





This could have happened sooner had the global financial crisis and the associated crude

price volatility muddled the waters. On the conventional side of the crude business, where

there is more diversity in the nature of the participating companies, the fiscal situation, drop

in oil prices and crude consumption patterns – all came together to create the perfect storm.

CAPP notes that this contributed to the decline in overall activity either side of the global

credit crisis.

Canadian Oil & Gas Investment Spending with 2011 projects (Click to enlarge) © CAPP

“The oil sands business sees large cap projects where investors do not make investments

based on the immediate fiscal environment. I would say that the fiscal shock, which createduncertainty in markets made people more reticent when it came to making investments. This

combined with the impact that it had on the costs of inputs, services and supplies to oil sands

projects gave a number of companies a cause to pause in their investment plans,” Collyer

notes.

However, the economic downturn both globally and locally caused input costs to go down by

20 to 25 per cent. Due to the economics, long term forecasts remained the same but still

companies paused to get a sense of the risk, macro environment and impact of the crisis over

the medium term and felt that in a year or two they would be in a better position to move

forward with the project.

CAPP notes that the projects on hold are now back on in terms of finance procurement,

development or construction and the pressure we are now seeing is that when activity ramps

up – some of the cost pressure is coming back into the system. “Time will tell whether this

pause in activity translated into a cost advantage. Both conventional energy and oil sands

business felt the impact,” Collyer notes.

Legal and financial advisers are cautiously optimistic too, but stress that the market dynamics

and the historical context need to be understood.





Brian Pyra, Calgary-based partner at Deloitte (Canada) notes that some five to eight years

ago the small and intermediate size energy companies got involved in the oil sands because

they did not have production from other sources and had to rely on equity finance to support

Greenfield opportunities which took six to seven years to yield.

“Given this historical context, there are two things here. Firstly, back then lenders would not

lend money to smaller players, especially on favourable terms given the oil sands risk profile

and there being near negligible or uncertain return on investment for a minimum of six to

eight years given the extraction technologies at the time,” he notes.

“Secondly, when signs of a yield were witnessed, smaller players sold out their projects to

larger companies. These have since invested in a basket of assets – Shell, Suncor and

ExxonMobil to name a few. But as the investment cap increases, for the oil majors a part of it

will always be equity financed but some portion could be debt financed. We should be

cautiously optimistic. In fact, the larger the project and its sponsor (and given that most

upgraders, i.e. processing projects which treat oil sands bitumen to transportable crude for

refineries, are large-cap projects), the more there is a chance of the debt markets being

approached,” Pyra adds.

The only caveat is that a change of mindset may be merited for that to happen meaningfully.

Everything could be tied up for up to eight years on a typical Greenfield oil sands project

depending on its exploration and production (E&P) nature and lenders traditionally have

trouble lining-up behind these projects.

“Furthermore, as the profile of the oil sands continues to rise, now we have the National Oil

Corporations (NOCs) coming in and they have the cash to do whatever they want and rarely

approach the debt markets,” Pyra concludes.

Legal impediments, petroleum security & investment

In more ways than one, Canada has one of the most stringent energy regulatory

environments in the business. Its E&P onshore and offshore industry have a very good safety

and environmental record. However, those who thought BP‟s Macondo fiasco which tarred

offshore prospection would make things easier for regulating oil sands prospection projects

have been proved wrong. On the contrary, the reverse happened as the oil sands

developments got dragged into the wider debate on unconventional hydrocarbon prospection.

Top Five Oil Sands PF Deals By Valuation 2005-2010 (Click to enlarge) © Infrastructure Journal






Top Five Conventional PF Deals by Valuation 2005-2010 (Click to enlarge) © Infrastructure Journal

Scott Rusty Miller, legal consultant at Ogilvy Renault, Calgary (now Norton Rose OR LLP, part

of the Norton Rose Group) notes that when looking at an energy project – the finance is long

term; the diligence is current while the product being extracted is sold on a short term basis

on completion.

“Financing energy projects is one of the most challenging undertakings by the finance

community among all infrastructure sectors as the returns usually take three to five years at

the very least and a product is to be sold at market prices when the project comes

onstream,” he adds.

Miller notes that for over 30 years, the regulatory burden both in Canada and US has

consistently been increasing and not decreasing. “That‟s not withstanding efforts to

streamline regulatory processes either side of the border and reduce massive oversight to

effective oversight. The regulatory burden has gone up and it has gone up because people

have greater interest – they are more involved and which was not the case before,” he adds.

Alberta‟s rising population means more concerns are raised these days when a prospection

well or a pit is dug whereas some while ago if drilling activity took place in a remote corner of

Western Canada, the same level of concern was not there.

“The systems are encouraging involvement in Alberta and beyond. If you are an individual

who is directly affected then you can claim costs to mount an opposition to a project. You get

funding both at federal and provincial level to hire an expert and present a case (or counter

case depending on circumstances). Now, if you hire good experts, they raise good questions

– either way it increases the time load and the effort required by a project‟s legal team to

answer those questions. Keystone XL project is a prime example of an “educated” opposition

which is well funded,” Miller continues.

Furthermore, extraordinary events always raise the level of concern. For example, Exxon

Valdez caused a universal move to double hauled vessels, different insurance rates, new

legislation and new shipping infrastructure. “Now we have the BP incident and recent events

in Japan to cite,” he says.

CAPP notes that regulatory framework in Canada had more separation of responsibilities

delegated to different monitors and is more robust than what we saw in the US Gulf Coast

prior to the Macondo accident. This view is supported by a number of inquiries which have

taken place in Canada since then.

Collyer adds that more regulation is not necessarily better regulation. “So you would have to

look at risk assessment studies and regulations appropriate to the activity in question. Having

said that, there is no question that we will get more regulatory oversight, on what are

deemed to be higher risk activities in any jurisdiction and to be honest that is also reflected in

public opinion whether its offshore, shale gas or oil sands,” he says.




What works in the developers‟ favour is that survey data suggests the vast majority of

Canadians want responsible development of oil and gas and are not opposed to development.

They acknowledge the economic benefits and are fairly pragmatic about what can be done by

the industry on the environmental front and green commitments made by the industry

players.

“But we also have the more extreme factions who are opposed to any form of hydrocarbon

development. They are effective, often well funded and they take it upon themselves to

oppose most types of oil & gas activities these days. The increased regulatory and public

scrutiny post-Macondo has created an environment where there is more latitude for

opponents of hydrocarbon development to intervene in regulatory process(es). Delays

translate into costs – this is a tension the industry has to collectively manage,” Collyer says.

From approval to financial close, the length of time oil sands projects would take coming

onstream is likely to go up and evidence suggests it already is but this is not necessarily

dampening interest.

“You simply have to show your client the magnitude of the tasks and the associated legal

costs. There is no way to camouflage this in the energy project finance business. Costs have

to be borne by the sponsor and factored in to the project cost (whether the project debt

markets are approached or even if it‟s a wholly equity-financed project). Sometimes that

scrutiny or burden is going to result in frustrating the project,” Miller notes.

For example, there is natural gas in the McKenzie delta area and the Arctic islands of Canada.

There has been a proposal to build an Arctic gas pipeline since the 1970s which would bring

gas from that area down to interconnect with the existing pipeline system and in the North of

Alberta. That was postponed once in the 1970s. Then in the 1990s it was revived again and

the regulatory process for that pipeline took ten years. It got final approval from the

Canadian federal cabinet in January 2011.

“In that time, natural gas price of US$7 mcf has come down to the US$4 range. But project

costs have gone seven times over in the last five years alone. If you burden a project with

that type of a time burden – I think even a rational person would say it could kill the project.

On the other hand, regulators (in Canada and indeed elsewhere) will protest that the

conditions have changed and they have to respond to the public will for more scrutiny. In

light of this, most financiers are near certain to say, first get your approval and then come to

us and we will price the debt appropriately,” Miller concludes.

Despite legal challenges, the investment climate remains conducive and petroleum security,

especially that of the world‟s largest consuming nation, the US, necessitates that the oil

sands projects proceed under scrutiny. Alberta itself has a provincial necessity; in recent

decades it has become a near petro-state and data suggests the oil and gas sector accounts

for 31.4 per cent of its GDP

[5]

.




Nearly 70 per cent of the world‟s remaining oil is under OPEC member jurisdiction, so how

can project developers afford to ignore a safe jurisdiction which is thought to hold the world‟s

second largest reserves of oil?

While his words caused a stir earlier this year, there was certain element of truth in the

current Canadian Minister of the Environment Peter Kent‟s assertion that: “Oil sands crude is

ethical in the sense that the proceeds of that oil goes to strengthen democracy, the

environment, the Canadian society; it doesn‟t go off to support terrorism, injustice or

tyranny.”

Political manoeuvring aside, the investment climate in Canada has never been better as, post

crisis, profitability is seen returning.

“Post crisis, the oil price is at/around US$100 plus. I feel this is the time when companies

would be very serious in looking at reigniting previous stalled projects and they will require

financing. It‟s reached a point where an oil sands project sponsor can convince financier(s)

that component costs are under control and the oil price looks relatively healthy. More

importantly, over the medium term this is the perfect condition for ensuring a good balance

between debt and equity. If debt markets need convincing about the oil sands – and it won‟t

be easy – now would be a good time,” Miller notes.

Oil Sands Transactions 2007-2010 (In US$ unless stated otherwise, Click to enlarge) © CAPP

“Remember, these are 40 to 50 year production facilities and with the oil sands we are taking

about a resource that will easily do a 100,000 barrels a day for five decades. So you take it at

one end and sell in the other – the largest consuming market – the US. That‟s got to be

pretty attractive to financial entities – especially when you add in the fact that the sponsors

in question are solid entities of established corporate credentials themselves – be they

Canadian or international operators in Western Canadian provincial jurisdictions,” he

continues.





Canada has well-established foreign investment criteria and all foreign partnerships, stakes

and acquisitions in the energy business are evaluated on the basis of a benefits test that has

to be passed. CAPP‟s view here is that it is a global industry – investment capital is mobile

and they need investment in the energy business in Western Canada. Certainly the Alberta

provincial government and indeed the federal government see foreign investment in a

favourable light if the established criteria are met.

Capital infusion is welcome, and in some cases may even assist in getting challenging

projects off the ground as interest from Asian players, especially China, rises. Pyra of Deloitte

notes that when Canada looks at foreign direct investment, the country‟s attitude is largely

welcoming and less politically vitriolic. “Very rarely does the Federal or Provincial government

feel a line has been crossed and block a deal,” he concludes.

Building BRIK by BRIK & the “Growth” Case?

Alberta‟s oil sands frequently witness upgraders but on February 17, 2011 the province

observed something rather unique. As part of his long term commitment to encourage

refining and upgrading and get more value from provincial resources within its borders, Ed

Stelmach, the outgoing premier of Alberta took a huge plunge into the upgrading world.

He announced that the province would supply bitumen it collects from Alberta‟s oil producers

as a royalty to support the construction of a CAD$5 billion (US$5.06 billion) bitumen refinery

by partners North West Upgrading Inc and Canadian Natural Resources Ltd. The move was

described as a BRIK – Bitumen Royalty in Kind.

His office told IJ that the first phase of the refinery is targeted for completion in 2014 with a

capability to process 37,000 barrels per day (b/d) of provincial government bitumen for a

processing fee, on top of 12,500 b/d from Canadian Natural Resources, which would build

and run the project. The spokesperson also said that if all three phases go ahead – the

refinery near Edmonton will process 150,000 b/d of bitumen into ultra-low-sulphur motoring

fuels, naphtha and diluents which the provincial government hopes to sell at a higher price.

In a highly complicated infrastructural additive, to project according the IJ‟s database will be

the only one in the world to combine gasification technology with CO2 management. Figures

suggest it will have a capability to capture 1.2 million tonnes of CO2 per phase which will then

be sold to Enhance Energy‟s Alberta Carbon Trunk Line for use in projects aimed at enhancing

oil production.

Environmentalists derided it, the market buzzed about it and project financiers joked that it

was first oil sands public private partnership in the world. Some commentators said it was too

expensive, others said it was too complicated, yet everyone agreed the project may not have

taken off had the government not stepped in. This is likely to offer some comfort to the wider

market about the government commitment.




CAPP notes that there is already a fair bit of upgrading taking place in Alberta – about 60 per

cent of the bitumen that is produced in Alberta is upgraded within the province. The rest is

exported as bitumen to the US.

“The NorthWest Upgrader is a bit unique in that it is somewhat of a standalone project and

the Alberta government has committed itself to supporting it. So there is a supply guarantee

to that project. They essentially proposed to upgrade the project on a fee for services basis –

which makes it unique in the respect that it is backed by the provincial government by taking

the bitumen molecules/barrels and committing themselves to this project,” Collyer says.

“Whether we will see more of this, it is difficult to say at this point in time. The p rovincial

administration also sees it as an encouragement to economic activity and job creation. It is

clearly a step in the direction that Alberta has not taken before with respect to oil sands. So

the project structure is quite unique and there are arguments in its favour. We see bulk of

the investment being privately financed and supported by equity or debt markets and that is

going to continue. This is a specific measure that the province adopted to address this

particular challenge. I would not hold it to be indicative of a broad policy change certainly in

terms of intervention by the province and what otherwise would be a market decision,” he

concludes.

Some feel the genesis of government involvement is that it wanted more value-added

production to take place in Alberta itself with job creation being a motivation.

“People who built upgraders got unquestionably bogged down by the economic downturn but

they were also looking at a minimum five to eight year return on investment, hence the

government stepped in for this special case. But what government involvement does is, it

signifies commitment – that some or large parts of the project in question would be built.

That is duly noted by the commercial loan providers – but it‟ll be one among many factors

they would consider before getting involved in an oil sands project,” Pyra says.

Whatever the merit or the demerits, many opine that the government has now gained a

greater understanding of the oil sands business, the risks and concerns of the operators and

how they are regionally taxed. Pyra notes that it has put in place a royalties regime which is

much more favourable to market conditions.

“If the tax system is fair and the royalties system is fair for both sides – then the playing field

has been balanced. For instance, the UK Conservative-led coalition government has increased

taxation dramatically for its North Sea operators; the approach of their Conservative

counterparts in Canada with relation to the oil sands business has been more nuanced – both

federally and provincially,” he adds.

The production growth case is solid. The oil sands are in three major regions concentrated in

Northern Alberta – Athabasca, Cold Lake and Peace River deposits. According to CAPP and

the Alberta Energy resources and Conservation Board (AERCB) these together contain some

170 billion barrels.




Map of oil sands in Alberta, Canada (Click to enlarge) © CAPP

Canadian crude comes in four forms categorised by viscosity, sulphur content and processing

mechanism. These are Conventional Light, Conventional Heavy, Upgraded Light and Bitumen

Blend, with latter being further sub-categorised as upgraded heavy sour, SynBit (bitumen

diluted with upgraded light oil) and DilBit (bitumen diluted with condensate, mostly Pentane

plus).

Collectively in relative barrel terms for the year 2010, the production growth case (for both

conventional and unconventional) came in at 2.83 million barrels per day (m b/d). The

growth is projected to rise 3.48 m b/d, 4.21 m b/d and 4.74 m b/d by 2015, 2020 and 2025

respectively. After the financial crisis, many producers have returned back to the market and

oil sands production currently makes up 58 per cent of Western Canada‟s total crude

production according to CAPP.





Canadian Oil Production Projections by Source (Click to enlarge) © CAPP

Simply put, the crude growth case and volume matters, or bluntly put, according to Miller of

OR, “What‟s better drilling a US$30 million prospection well offshore with no guarantee of

whether you will hit oil or not or here in Canada where there is a proven resource?”

The resource is proven and its neighbouring leading export market is established – the big

question is the infrastructure needed to get it there and the politics which accompanies it all.

Those pipelines, the politics & why they are needed

In order to move the product from Canada, while rail is used, pipelines are the best option

whether we are talking accessing Asian export markets via tankers from the Pacific Coast or

exporting to US refineries across the border. Keystone project and its extension Keystone XL

[Projects Database] remain the most vital, and also the most debatable piece of pipeline

infrastructure in North America.

The original pipeline which links Hardisty (Alberta, Canada) to Cushing (Oklahoma, USA) and

Patoka (Illinois) became operational in June 2010 just as an atypical US-Canadian tussle was

brewing. The extension project first proposed in 2008, again starting from Hardisty but with a

different route and an extension to Houston and Port Arthur (Texas) is still stuck in the

quagmire of US politics, environmental reticence, planning laws and a bituminous mix of the

Canadian oil sands.

Since it is a cross-border project, US secretary of State Hillary Clinton has to mediate, and a

pattern seems to be emerging. A group of 14 US senators here and 39 there with their

counterparts across the border would write to her explaining the merits only for

environmental groups to launch a counter representation. Several agencies are also in the

mix and that has been the drill since Clinton became US secretary of State when the Obama

administration assumed office.








All Proposals for Canadian and US Crude Oil Pipelines (Click to enlarge) © CAPP

The need for an extension is exactly what formed the basis of the original Keystone project –

Canada is already the biggest supplier of crude oil to the US; and it is only logical that its

share should rise and in all likelihood will rise. Keystone XL according to one of its sponsors –

TransCanada – would have the capacity to raise the existing capacity by 591,000 barrels per

day though the initial dispatch proposal is more likely to be in the range of 510,000 barrels.

According to Fitch Ratings, the current price differential between Brent-WTI could jumpstart

additional M&A or capital expenditure investments in the US Midcontinent downstream, aslocal refineries seek to situate themselves better to capture any longer term Canadian and

Shale differentials. Pipeline project delays are prolonging the differential.

Fitch reckons that due to the delays in permitting Keystone XL from Cushing to the Gulf of

Mexico Coast – now not expected at least until 2013 – and other pipeline announcements not

expected to result in completed steel in the ground for some time, the price differential may

persist for at least the next several quarters.

If the legislative wrangles are discounted, over 2010 both debt and equity capital market

access remained resilient or improved in pipeline, midstream and master limited partnerships

(MLP) sub-sectors. Fitch notes that market participants continue to enjoy increased flexibility

and favourable debt pricing terms. Furthermore, interest rates in the US, if not Canada, are

also expected to remain relatively low throughout 2011.

Issuers have been able to extend bank credit facilities for three to five year terms, typically

with acceptable terms, albeit at a higher cost. With a significant concentration of facilities

maturing in 2012, Fitch expects issuers and banks to be opportunistic in refinancing revolvers

in the coming year; a sentiment echoed by majority of IJ analysts‟ sources in the finance

community focussed on this sector in North America.





The problem with all aspects of Keystone, and other projects of its ilk, is that the opponents

of oil sands have got the narrative engrained in a wider debate on the environment and the

energy mix. Going forward, they view Keystone XL and other incremental pipeline projects in

the US as perpetuating reliance on crude oil and are opposing the project on that basis.

Everyone in Alberta admits work needs to be done by the industry to meet environmental

concerns. However, a 'wells to wheels' analysis of CO2 emissions, most notably by IHS CERA

and many North American institutions has confirmed that oil sands crude is only 5 to 15 per

cent „dirtier‟ than the US sweet crude mix.

US Market Demand for Canadian Oil in 1000 b/d in each Petroleum Administration for Defense District (Click to enlarge) © CAPP

The figure compares favourably with Nigerian, Mexican and Venezuelan crude which the US

already imports. So branding Canadian crude as dirty and holding up Keystone XL on this

basis comes across as strange whichever way it is examined. CAPP for its part takes a very

pragmatic line

“Do we think there is legitimacy in the argument that is being made against Keystone? No

(for the most part) but the reality is that there has to be due consideration in the US. I would

assume the US State Department is in a position where it has no alternative but to employ an

abundance of caution to ensure that all due processes are met. What frustrates Canadians

and Americans alike is the length of time that it has taken. However, at the end of the day

when we get that approval and it is a robust one which withstands a strict level of scrutiny

then it‟s a good thing,” Collyer says.

However, some like Pyra of Deloitte are nonplussed. “The Canadian industry, as opposed to

some other oil exporting jurisdictions is prepared to openly debate it and have the operations

independently scrutinised. Yet the rebuttal is often from a “misinformed” position. We started

with mining as far as the oil sands go and now we are going down the route of in-situ

processing. The mining component involves an open pit mine. I have visited open pit gold or





copper mines, and admittedly oil sands open mines are far larger and less spread out.

However, that does not imply these mines are unmanageable or not regulated,” he notes.

Far from that, Pyra opines that Canadian legislation is stricter than even the US in some

cases. “Canada, despite being having the largest deposits, is not the only country with oil

sands. Given the need for the resource, there‟s is nothing stopping these nations to exploit

the resource. Most observers may find none of these markets to be as open to outside

scrutiny as Canada,” he concludes.

Ask CAPP or any Toronto-based market analyst if Canada could look elsewhere and they

would get an answer back with a smile; only the Americans probably would not join them.

China, and to a lesser extent Japan and Korea, are fast emerging as rival export markets

where, according to sources, importing oil sands crude does not get a vitriolic reception as it

does in certain (but not all) quarters in the US.

Interest alone does not create a market – but backed up by infrastructure at both ends, it

strengthens the relationship between markets Canadians have traditionally not looked at. All

of this shifts emphasis on pipeline projects in the general direction of the country‟s West

Coast. On top of the existing Trans Mountain pipeline (300,000 b/d, Light/Heavy 80/20), the

following crude oil pipelines have been proposed:

Enbridge Northern Gateway: Originating at Bruderheim, Alberta and ending at Kitimat,

British Columbia (Capacity 525 thousand b/d)

Kinder Morgan TMX2: Originating at Edmonton, Alberta and ending at Kamloops, British

Columbia (Capacity 80 thousand b/d)

Kinder Morgan TMX3: Originating at Kamloops, British Columbia and ending at Sumas,

British Columbia (Capacity 300 thousand b/d)

Kinder Morgan TMX Northern Leg: Originating at Rearguard & Edmonton, Alberta and

ending at Kitimat, British Columbia (Capacity 400 thousand b/d)

In theory, if these projects reach financial close before Keystone XL, the balance could be

tipped in favour Canadians diversifying their export market to include others in a tussle with

the US for access to the oil sands. In practice, it is not that simple. To begin with, the leaders

of Canada‟s First Nations, (Native Indians) are opposed to pipeline(s) crossing their territory.

There is the inevitable pressure from environmental groups and worries about cost overruns,

especially those associated with Enbridge Northern Gateway.

Enbridge has not helped its own case by being involved in high profile fiascos such as the

appalling Kalamazoo spill last year when over 19,000 barrels of crude were split into the

Kalamazoo River and another spill in the Greater Chicago area. As required by law, Enbridge

has also recorded several leaks and breaks over the last decade.

Local commentators suggest a paradoxical connection with Keystone XL‟s approval. One

scenario is that if Keystone XL is blocked, the West Coast project(s) would be strengthened.

Anecdotal evidence suggests that a possible settlement involving monetary incentives and




stringent environmental safeguards backed-up by legislation is on the cards with the First

Nations‟ representatives. The Chinese are eyeing the developments.

“If you look at potential markets for Canadian oil and gas, then industry players are already

looking at Asia specifically China given the demand projections seen there. It is in the

Canadian producers‟ interest to build pipelines to the West Coast. It‟ll take time to get the

approval and construct them. The alternative export market is there and the US will have to

take its own independent assessment on whether and by how much it wants access to

Canadian oil,” Pyra observes.

Either way, the pipelines are crucial to Prime Minister Steven Harper‟s ambition of positioning

Canada as an energy superpower with ethics and scruples. This combination is possibly not

lost on US President Barack Obama.

At a recent event, the President said he would be targeting a one-third reduction in US crude

imports by 2025. “I set this goal knowing that we‟re still going to have to import some oil.

And when it comes to the oil we import from other nations, obviously we have got to look at

neighbours like Canada and Mexico that are stable, steady and reliable sources,” he added[6].

Keystone project could also help Canadians export surplus crude using US ports in the Gulf

and tax benefits could accrue not just at the Texan end but along the route as well. The US

State Department says it will conclude its review of Keystone XL later this year. The project

metrics are solid which leads IJ analysts to believe it will reach financial close possibly by Q1

2012.

A geopolitical quirk & the project financiers

That the oil sands are in Canada is a geological quirk, given the unpredictability of OPEC and

Russian supplies. They will, and some say already are, playing their part in an altering

landscape. In the 1950s, the erstwhile Seven Sisters – namely Standard Oil of New Jersey

and Standard Oil Company of New York (now ExxonMobil); Standard Oil of California, Gulf Oil

and Texaco (now Chevron); Royal Dutch Shell and Anglo-Persian Oil Company (now BP)

owned 85 per cent of crude oil production around the world outside Canada, USA, erstwhile

USSR and China[7].

Then OPEC emerged, Soviet discounts disappeared and NOCs part of the cartel began to

dominate. The private sector sponsors, Canadian government and indeed the new state

owned oil sponsors – especially Indian and Chinese NOCs – see the country‟s industry in

general and oil sands in particular as an oasis of geopolitical calm. Financiers also warm up to

the sentiment even though environmental concerns continue to give some cold feet.




Oil sands: There's a barrel of crude in there somewhere © Royal Dutch Shell

If 2011 alone will see CAD$15 billion worth of investment as CAPP says, how much of thatwill form the equity basis of project finance remains to be seen. Overall, all three major

rating agencies maintain a stable outlook for the North American oil & gas sector in 2011.

This is unchanged from 2010 and includes most sector sub-components.

Miller of OR notes how many projects seek debt market suitors depends on what price the

sponsor and financier feel is right or is likely to get, what is the demand, what ancillary

impediments, legislative and environment hurdles are there.

“Then it will narrow down to which sponsor and his club of financiers has the will to see this

through. On the mining side, the risks are very well understood and there is no mystery

about how you can operate an open pit mine, and there is a good understanding of both how

the upgrading of petroleum works and how the process can be made more efficient,” he adds.

Via “co-generation facilities” the industry is looking beyond steam as a method of mobilising

the bitumen. At present, two pilot projects are ongoing that use a different solvent – a light

end condensate – instead of steaming to mobilise the oil in the sand. They put in the solvent

and it releases the oil, mobilises it so that it may be pumped up. Then the oil is separated

from the condensate and the condensate is subsequently recycled.

If these pilot projects are successful this would reduce the greenhouse gasses substantially

and will mitigate water usage to generate steam, thereby replacing it with a solvent.




"There is a lot that can be done and I think the industry has seen that they have to do

something to bring down the greenhouse gases. Given that the target is 5 to 15 per cent less

than some of the other heavy sour crude varieties; I think that is quite achievable. However,

I describe environmental impediments as a “wild card”. For instance, some countries might

put penalties on what they see as “dirty oil” and but many others won‟t. There could be

losses and profits for both producers and consumers depending on the point of view that you

take,” Miller concludes.

A random survey by IJ of 11 energy sector professionals in Alberta suggests a crude price

range of US$75-80 per barrel would make investment in oil sands comfortable. Anything

above that and up to US$125 per barrel is a bonus.

However, if the oil price goes up activity goes up, as do the input costs – especially labour

and construction steel. So in the oil sands business – as price goes up cost structures start to

escalate and project developers should be mindful of this. On the other hand, a price below

US$50 per barrel is likely to stunt investment as was noticed in wake of the global financial

crisis when the price fell to US$37.50 at one point.

Given this backdrop there is more clarity about the investment climate in Alberta than four

years ago. Between fiscal year 2007-08 and at the time of publishing this report, Alberta has

gone through some significant royalty structure changes - not to mention the BRIK move by

the provincial administration.

CAPP notes that some components of the previous regime of royalties were controversial and

many likened them to an increase in the royalty structure. There was a fair bit of

consternation within the industry and in the end more importantly among investors when

they were introduced to the market conditions. Subsequently, there was a significant dip in

activity over Q1 2010 and migration of activity to other Canadian jurisdictions –

Saskatchewan and British Columbia most notably.

Ultimately, the Alberta royalty structure was changed back to something like it was before

the changes were instituted and seen since then there is a fairly dramatic turnaround in

drilling activity and a very significant amount of land sale activity which is always a leading

indicator about where the industry is going.

“I think Canada in general and Alberta in particular is better placed now than we were in

2007-08 in terms of the investment climate. I would say the consternation that both the

industry and investment community felt at the time is yet to work its way out of the system –

there is a hangover – but positive steps by the government on the fiscal and regulatory side

to address competitiveness issues over the last couple of years have ensured that it is a far

better place to develop energy projects than say two to three years ago,” Collyer says.

Additionally, there is growing recognition that Canada‟s energy landscape is not all about oil

sands. In March 2010, the Alberta Government announced that from January 2011, it would

give permanency to an incentive feature of its royalty system programme that limits the



royalty rate on new conventional oil wells for the first 50,000 barrels of production to 5 per

cent. Going further, the Government also announced that the maximum royalty rate for

conventional oil would be reduced at higher price levels from 50 per cent to 40 per cent[8].

In the opinion of market commentators such fiscal measures would bolster the attractiveness

of developing conventional oil projects in Alberta alongside oil sands projects. However, for

project financiers looking for a conventional opportunity, the most promising one is not in

Alberta, but East Saskatchewan – the Bakken oil play. Manitoba‟s increasing switch from

traditional vertical wells to horizontal drilling also offers opportunities.

CAPP feels it is now a matter of convincing more players in the industry and investment

community that the oil sands are in a much more stable place. They can count on the

infrastructure that is now in place and will be so for the foreseeable future. Most operating

parameters, especially taxation matters are never static, but of late Alberta has signalled its

competitive intent and with some purpose. Feedback is that investors and financiers are

taking that on-board.

With additional reporting by the author from Fort McMurray (Alberta, Canada), Kitimat,

(British Columbia, Canada) and Houston (Texas, USA)

The author gratefully acknowledges the off-record and on-record insight of several industry

professionals who spared their valuable time to discuss his findings and the subject of this

report.

Disclaimer: Please note that the commentary and opinion of individuals from third party

institutions contained in this report are solely theirs and not those of the institutions they

represent or work for. This report is a data and trends based assessment of the industry. It

does not explicitly or implicitly constitute investment advice or an endorsement either by the

individuals and institutions quoted or by Infrastructure Journal.

NOTES:

[1] CAPP, IEA, US EIA aggregate

[2] IHS CERA

[3] CAPP, IEA, US EIA aggregate

[4] Sayer Energy Advisors, Canada, Published data May 2011

[5] StatsCan

[6] Speech by US President Barack Obama, March 30th, 2011 at Georgetown University, USA

[7] Oil Policies, Oil Myths By Fadhil J. Chalabi, Published in 2010 by I.B.Tauris. Available here.

[8] Alberta Energy Ministry, Mar 2010

This report was first published by Infrastructure Journal on June 6th , 2011.

http://www.ibtauris.com/Books/Economics%20finance%20business%20%20management/Industry%20%20industrial%20studies/Energy%20industries%20%20utilities/Petroleum%20%20oil%20industries/Oil%20Policies%20Oil%20Myths%20Analysis%20and%20Memoir%20of%20an%20OPEC%20insider.aspx?menuitem=%7bDC8AC939-3911-4A4D-B039-0D747793C130%7d




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Canada O&G Outlook 2011: Oil Sands ready for PF debt?

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