ARC Report - Turmoil and Renewal

April 2011

TURMOIL AND RENEWALThe fiscal pulse of the Canadian upstream oil and gas industry

A five-year review and outlook

Peter TertzakianKara Baynton

April 2011Turmoil and Renewal

About ARC Financial Corp. and the Authors

i

ARC Financial Corp.ARC Financial Corp. (“ARC”) is an energy-focused private equity firm based in Calgary, Alberta Canada, with $2.7 billion of capital across six ARC Energy Funds. Leveraging off the experience, expertise, and indus-try relationships of more than 25 investment professionals, ARC invests in upstream oil and gas, oilfield services, energy infrastructure and renewable energy.

ARC offers world-class research, analysis and strategic planning estab-lished through technical and operating industry experience. Through this deep domain knowledge and energy capital markets expertise, ARC plays a valuable role in the companies they finance and to the Canadian oil and gas industry as a whole. Employing best practices in corporate governance and business processes, ARC builds successful companies through transac-tional advice, deal sourcing and evaluation support.

ContactARC Financial Corp. 4300, 400 - 3 Avenue SW Calgary, Alberta CANADA T2P 4H2

Phone: (403) 292-0680www.arcfinancial.com

The Authors Peter Tertzakian, Chief Energy Economist and Managing Director, ARC Financial Corp.

Peter Tertzakian is the Chief Energy Economist and a Managing Director of ARC Financial Corp. Best selling author of A Thousand Barrels A Second (McGraw-Hill, 2006) and The End of Energy Obesity ( John Wiley & Sons, 2009), Peter is responsible for ARC’s strategic investment research and oversees the publication of ARC Energy Charts, a weekly journal of energy trends. He is often seen or quoted in high-profile media outlets, including a guest appearance on The Daily Show with Jon Stewart. Peter’s 30 years of experience in geophysics, economics and finance have established him as an internationally recognized expert in energy matters. A highly sought after guest speaker, Peter routinely advises corporate leaders, investors, gov-ernment officials and students around the world.

Kara Baynton, Manager, Energy Research, ARC Financial Corp.

Kara Baynton is the Manager of Energy Research at ARC Financial Corp. where she is responsible for analyzing energy commodity prices, business cycle timing, technological trends and capital markets. She has followed the upstream Canadian oil and gas industry for almost 15 years, with spe-cialty in constructing and maintaining the economic models of capital flow underpinning this report. Kara joined ARC in 2002 after having spent more than five years researching energy equities in the investment banking business. She has a B.Comm in Finance from the University of Calgary, and holds a CFA charter.


AcknowledgementsEighteen months ago we were hesitant to accept the request from

the Canadian Association of Petroleum Producers (CAPP)to conduct another formal analysis of Canada’s oil and gas industry. Knowing all too well the tremendous effort it takes to research, write up and publish a report on such a large, complex and time-consuming subject, the deci-sion to give the “green light” was taken only knowing that support would be available from highly qualified partners.

We would like to thank the many people inside and outside the indus-try that contributed, advised and scrutinized the numbers, charts and words contained in this report. Many thanks to David Daly of CAPP, who patiently quarterbacked questions, concerns and acted as a liaison to many trusted readers. As well, special gratitude goes to the tax group at Connacher Oil and Gas, whose assistance on intricate tax considerations in the economic models cannot be understated.

It’s often said that the last 5% of such a work takes 95% of the effort. For the homestretch, we are indebted to those who patiently took time to read the document word-for-word and helped to identify errors, omissions and vague concepts. Because of their efforts this report is more accurate, independent and forthright.

Finally, we wish to acknowledge the patience of family members that inevitably shoulder a burden of the authors’ stress whenever the light turns green on such time consuming projects.

Peter TertzakianKara Baynton

DisclaimerThe content of this document is the property of ARC Financial Corp.

(“ARC”) and may not be reproduced, republished, posted, transmitted, distributed, copied, publicly displayed, modified or otherwise used in whole or in part without the express written consent of ARC.

Certain information contained herein constitutes forward-looking information and statements and financial outlooks (collectively, “for-ward looking statements”) under the meaning of applicable securities laws. Forward looking statements include estimates, plans, expectations, opinions, forecasts, projections, guidance or other statements that are not statements of fact. Although ARC believes that the assumptions under-lying, and expectations reflected in, such forward looking statements are reasonable, it can give no assurance that such assumptions and expecta-tions will prove to have been correct. Such statements involve known and unknown risks, uncertainties and other factors outside of ARC’s control that may cause actual results to differ materially from those expressed in the forward looking statements.

Performance histories are not indicative of future performance. Invest-ment returns will fluctuate and are not guaranteed.

This document is provided for informational purposes only and shall not constitute an offer to sell or the solicitation of an offer to buy securi-ties. None of the information contained herein is intended to provide investment, financial, legal, accounting or tax advice and should not be relied upon in any regard.

In connection with the preparation of this information, ARC may have relied upon data provided by external parties. ARC does not audit or oth-erwise verify such data and disclaims any and all responsibility or liability of any nature whatsoever for the accuracy, adequacy or completeness of the data upon which ARC has so relied.

Acknowledgements and Disclaimer

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April 2011Turmoil and Renewal iii


Table of Contents

About ARC Financial Corp. and the Authors . . . . . i

Acknowledgements and Disclaimer . . . . . . . ii

Table of Contents . . . . . . . . . . . . . . iv

Industry Check-Up . . . . . . . . . . . . . . v

1 The Canadian Oil and Gas Economy 1

About this Report. . . . . . . . . . . . . . . 2

A Quick Look at Canada’s Endowment . . . . . . 3

Ten Themes to Follow . . . . . . . . . . . . . 4

2 The Fiscal Pulse 7

The Fiscal Pulse of the Economy . . . . . . . . 8

The Fiscal Pulse by the Numbers . . . . . . . . 9

Major Trends and Issues Around the Fiscal Pulse . . 12

3 Detailed Examination 19

Canadian Hydrocarbon Production . . . . . . . . 20

Commodity Prices . . . . . . . . . . . . . . 22

Upstream Industry Revenue . . . . . . . . . . 28

Taxes and Royalties . . . . . . . . . . . . . 30

Cost Indicators . . . . . . . . . . . . . . . 32

Cash Flow and Capital Spending . . . . . . . . 34

Capital Markets . . . . . . . . . . . . . . . 36

Land Bonuses . . . . . . . . . . . . . . . . 38

WCSB Well Trends . . . . . . . . . . . . . 39

Drilling and Completion Costs. . . . . . . . . . 42

Reserve Additions . . . . . . . . . . . . . . 43

4 Economic Viability 45

Finding and Development Costs . . . . . . . . 46

Industry Returns . . . . . . . . . . . . . . 48

Value Creation . . . . . . . . . . . . . . . 50

5 Sensitivity Analysis, Tables and Footnotes 51

Fiscal Pulse with Varying Oil and Gas Prices. . . . 52

Data Tables . . . . . . . . . . . . . . . . . 56

Footnotes . . . . . . . . . . . . . . . . . 61

Glossary . . . . . . . . . . . . . . . . . . 62

About CAPP . . . . . . . . . . . . . . . . 63

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Industry Check-Up

As you open this report, think of Canada’s oil and gas industry as a medical patient that has come in for a fiscal checkup. Let’s review the results of our examination.

Capital flows around Canada’s hydrocarbon economy like a pulse beating over 100 billion dollars every year through complex arteries and veins that weave into head offices, government treasuries, oilfield workers and the accounts of countless others that have direct or indirect ties to the business. The wide arteries that carry over $19 billion in royalties, land sales and tax dollars, and $43 billion of investment into in-frastructure and jobs, engender every Canadian a stakeholder in the annual pulse of capital that flows from the largest industry in the country.

The numbers and charts in this report are enough to overwhelm any financial medic trying to diagnose a complex case. Making matters more difficult, the patient’s last half-dozen beats, between 2005 and 2010, have been akin to an EKG needle skidding off both sides of a strip chart.

An assortment of easy medical metaphors come to mind to describe the succession of ailments experienced by the Canadian oil and gas industry over the past six years: High blood pressure (rapid influx of capital causing infla-tion); low blood pressure (revenue loss from the Financial Crisis); temporary blood loss (migra-tion of investment to other jurisdictions); medi-cal interventions (government policy implemen-

tations); trauma (aggressive competitive assault by US shale gas); constricted arteries (limited export outlets); group therapy (collaboration be-tween government and industry); new vitamins (influx of foreign capital); and healing (adapting to new competitive realities).

We have noted physiological and psycho-logical changes within our patient too: The tendency toward a higher carb diet (a progres-sive bias to oil over natural gas); growing pains (an increase in capital circulation); weight gain (a steadily rising cost structure); maturity (the migration to resource plays); heightened sense of hygiene (obligatory environmental aware-ness); improved cognitive response (adoption of innovative new processes for productivity gain); and moodiness (volatile profitability).

All these observations have been diagnosed, noted and discussed in our report, but in the end the patient wanted the answer to only one ques-tion, “Am I healthy, doctor?”

Unfortunately, the answer doesn’t lend itself to an easy “yes” or “no”, because the prognosis for Canada’s largest industry is not easy to characterize. For example, difficulties arise, because the patient does not exist uniformly as one, but as three seperate businesses: natural gas, oil and oil sands. All combined, you will see that outward health metrics like revenue, cash flow and investment look very positive over the next five years. But aches, pains and vulnerabilities are still to be found beneath the

collective veneer of multi-billion dollar financial statements – for example on the natural gas side of the industry – and the potential for econom-ic trauma always looms large in this acutely capital-intense, competitive business.

Like any advice-seeking patient who appears spry, but always feels anxious from warning symptoms, the Canadian oil and gas industry never has a shortage of second opinions willing to prognosticate. No more so than now when discussions about a national energy strategy are getting louder. Depending on whether you are a corporate leader, an investor, a policy maker, an academic, an employee serving the business or simply a concerned Canadian citizen, you will interpret the charts, numbers and trends in this report with a different diagnostic attitude and come away with a unique set of recommenda-tions.

But can we even agree on what is “healthy?” Despite inevitable divergences of opinion among stakeholders, we may all concur that an ideally functioning industry might entail a statement like: “Canada’s oil and gas industry operates best when there is a sustained flow of growth capital – not too much, not too little; not too fast, not too slow – that with each successive pulse delivers increasingly rewarding levels of prosperity to all stakeholders, within the bounds of world-class regulatory standards.”

Unfortunately, such a clinical, stable state will never exist. Competitive threats, capital

v


Industry Check-Up

flow constrictions, the nagging push of costs, tightening environmental standards, and market constraints are some of the many issues that will keep challenging the industry’s prosperity. And of course, the contagion of a commodity price collapse always brings unexpected trauma, much like the flu can suddenly debilitate us at inop-portune times. So, our examination shows that the patient is only “healthy” during fleeting mo-ments, but that is just a normal state of being.

The ongoing prescription is actually quite clear, though easier said than administered. First, understanding the industry, its scale, and what makes it tick is paramount to any discourse about its future. Canada’s oil and gas industry is of a size that matters to the world’s supply-demand balance, especially North America’s. Finding, developing and delivering valuable hydrocarbon resources responsibly and optimally, while at the same time balancing the ongoing troika of energy-related challenges – environmental sustainability, energy security and economic prosperity – demands deep knowledge by everyone who is involved in trying to keep the business healthy. We hope this report pro-vides stakeholders with greater insight into the financial dimension of their oil and gas industry and encourages decision makers to deepen their knowledge even further.

Secondly, industry and government will need to collaborate doubly hard on key issues that cannot be addressed by each indepen-

dently. Both must ally to avoid policy “shocks” that can inflict mutual malady. Clear, construc-tive and ongoing dialog will be essential to maintaining the confidence of stakeholders that provide capital to the fiscal pulse.

Urgent agenda items over the next five years include addressing policies on labour, environ-ment and market access. While an increas-ing capital flow allows the industry to grow, it also strains the availability of skilled workers, threatening inflation that will potentially price Canada’s products out of the global market. Policies relating to carbon emissions and other matters of environmental sustainability require long-term views to clearly define the bounds within which the industry can operate and in-novate. Canadians are forfeiting substantial tax and royalty income by not diversifying hydro-carbon exports to higher-paying global mar-kets beyond the United States; infrastructure to transport oil and gas abroad is imperative if the industry is to avoid material price discounts on 2.9 million BOE of net daily exports. For natural gas, failure to open up new markets will also limit its growth potential. These and other issues at hand demand interaction between industry leaders and many government agencies, not just those directly associated with energy and resources.

Finally, it’s important to recognize that the oil and gas industry is not one average entity as our charts and numbers suggest. Several thousand

diverse companies of varying sizes, each of which operates in their niches within millions of square kilometers of oil and gas endowment, compose the industry and its supporting com-mercial activities. As in any industry there is a wide range of companies spanning the weak and the strong. Looking ahead, all companies – especially oil and gas, and oilfield service – will have to accelerate innovation efforts relentlessly. If there is one key lesson to be learned from the last five years it’s that realizing productivity gains by embracing new technologies, process-es and strategies are paramount for maintain-ing immunity from high costs, environmental pressures and competitive threats. Those companies that have not learned this lesson will be quick victims of Darwinian selection.

In fact, evolutionary biology is not a new con-cept for this veteran industry. Periodic trauma has long been a catalyst for making progressive companies in Canada’s 150-year old oil and gas industry stronger and stronger, smarter and smarter with each successive pulse of capital flow. We can take some comfort in this survival-of-the-fittest evolutionary cycle, but it should not reassure us into complacency. Fiscal health is never guaranteed, especially in today’s rap-idly changing energy markets.

Now it’s time to leave the medical metaphors and dig deep into the numbers and methodol-ogy. We hope you enjoy this report and take the time to form your own diagnosis.

vi

April 2011Turmoil and Renewal vii

1 April 2011Turmoil and Renewal

Section 1

The Canadian UpstreamOil and Gas Economy


About this Report

Think back only half a dozen years. In 2005, we were amazed by the unabating bull run in commodity prices; a barrel of crude oil had more than doubled in value from $US 25.00 to $US 55.00. Back then, significant themes in the Canadian oil and gas business also included the emergence of cost inflation and building excite-ment in unconventional resources such as the oil sands and coal-bed methane.

Understanding the finances of the oil and gas business was already challenging due to things such as proliferating income trusts and declining tax pools. Such issues and their consequences to the industry seem relatively minor as com-pared to events that would end up shaking the latter half of the decade, the six-year time slice between 2005 and 2010, that we refer to as the Focus Period.

The mettle of the Canadian oil and gas busi-ness was tested during the Focus Period. Policy shocks, a rising dollar, rapid technological change, the onslaught of shale gas and of course the Financial Crisis were among the many chal-lenges faced by stakeholders. Through it all, the industry dramatically changed its complexion, especially its mix of conventional oil, natural gas, bitumen and synthetic oil output.

Our intent in this report is to analyze and interpret the key indicators that have character-ized the upstream Canadian oil and gas econo-my over time, especially during the Focus Period.

Trends in product volumes, prices, costs, money flows, profitability and capital efficiencies are all tracked and analyzed. To that end, historical data fed into over 100 economic variables has been reconciled to the end of 2009 using the information that CAPP obtains from Statistics Canada. Other credible providers of raw techni-cal and economic data have been used as well.

Though all the final catalogued data for 2010 was not available at time of writing, confident estimates for the year have been made based on the aggregation of real-time proxy data up to and including December, 2010.

Of course, diarizing the past is the easy part. Forecasting the future demands many assump-tions that are open to debate during a time of continuous change in the industry. Despite the many uncertainties, reasonable assumptions based on the best knowledge available to us have been used to make detailed forecasts for the period between 2011 and 2015. We call this forward-looking time span the Forecast Period.

When peering into the Forecast Period, oil and gas prices remain the biggest unknowns, yet have the greatest influence on the industry’s fortunes. To remove author bias, Base Case com-modity prices for the five-year Forecast Period

were selected from the futures market. To ac-commodate inevitable deviation from Base Case prices, a special section in this report quantifies the sensitivities of the industry’s future financial performance from a matrix of varying oil and gas price scenarios (see page 52).

Historically, the entire oil and gas industry could be treated as one business selling hydro-carbons. However, in this report the oil sands — which now contribute over 40% of the industry’s revenue with distinct cost and productivity metrics — are dissected out of the total oil and gas industry for separate analysis where possible. The balance of the industry, everything but the oil sands, is termed traditional oil and gas.

We have examined the industry by geography too. The onset of substantially different fiscal regimes in B.C., Alberta and Saskatchewan necessitated a look at key metrics on a province-by-province basis. We present detailed compara-tive Tables by province on pages 58 to 60.

Of course interpretations of the past and prognostications into the future hide behind veils of subjectivity, especially when there are so many moving variables and trends in play. We have done our best to preserve objectivity, but encourage those who digest the many charts, tables and notes in this document to interpret the factual information for themselves and develop their own view of Canada’s oil and gas future.

“Of course, diarizing the pastis the easy part”


A Quick Look at Canada’s Oil and Gas Endowment

Canada’s Oil and Gas IndustryGeography of Resource Endowments and Pipeline Infrastructure

Canada has one of the largest hydro-carbon endowments in the world. For over 150 years entrepreneurial oil and gas companies have been tapping into those resources to serve domestic energy needs and build prosperity through exports to the United States.

Though the industry started in Southern Ontario in 1858, the bulk of Canada’s reserves lie in a swath of hy-drocarbon-rich geology that spans from the Arctic Ocean down to southeast Saskatchewan. Offshore Newfound-land and Nova Scotia are home to large producing deposits as well.

Accessibility and economics have concentrated the bulk of exploration and development to lucrative areas of the Western Canadian Sedimentary Ba-sin (WCSB) that stretches from north-eastern B.C. diagonally southeast to the southwestern corner of Manitoba. This vast region contains a wide spectrum of hydrocarbons from natural gas to oil of varying grades, including oil sands.

A century-and-a-half of investment has resulted in an intricate network of pipelines and infrastructure, making Canada one of the most advanced pro-ducers of oil and gas in the world. After 150 years of exploration and development Canada is one of the most

advanced and prolific producers of oil and gas in the world.


A Bit of HistoryWe can only imagine the faces of wonder-

ment when the first European explorers set foot upon the Athabasca oil sands. Peter Pond, a fur trader, was reported to be the first European to kneel down and rub the mysterious gooey substance through his hands in 1778. Over 100 years would pass before the nascent Alberta petroleum industry would ship product from the oil sands region to upstream buyers. The oil was shipped truly upstream; in 1914, a scow carry-ing a meager shipment of no more than a few barrels of oil sands was pulled 375 km against the mighty currents of the Athabasca River. For days, sweaty workers on the river banks of the

Athabasca steadfastly heaved on a rope at-tached to the barge until the first valuable cargo reached its market.

In fact, Canada’s oil and gas industry predates the first oil sands cargo by 55 years. This coun-try’s first oil was produced in Lambton County, Ontario where a vibrant industry took root after the first commercial barrels were produced in 1858. The petroleum spotlight shifted west to Alberta, forty years later, at the turn of the last century, when significant traditional barrels were discovered at the foot of the Rocky Mountains. Natural gas production too was making a debut at the start of the 20th century with first vol-umes being brought to market from the shallow geology beneath the town of Medicine Hat in southeastern Alberta.

Since the early 1900s the Canadian oil and gas industry has been rich with world scale milestones like Imperial’s Leduc No. 1 discov-ery in 1947, Dome Petroleum’s Arctic drilling ventures in the early 1960s, the first major oil sands plant commissioned by Great Canadian Oil Sands in 1967, Hibernia’s first oil in 1997, and more recently the excitement surround-ing vast resource plays like those in northeast-ern B.C. and southern Saskatchewan. These milestones and many more have contributed to making Canada’s upstream oil and gas industry one of the oldest, largest and most versatile in the world.

The six-year Focus Period between 2005 and 2010 is a mere blink in the industry’s history, but ranks as among the most turbulent time slices in the business. Extremes of boom and bust were tested in a very short period of time as capital flow went from a gush in 2007, to a trickle in fall 2008, only to open up again in late 2009. In living memory, oil patch veterans would probably agree that only two other peri-ods could compete with the trauma experienced in the Focus Period: the early 1980s, after the National Energy Program, and the late 1990s when a surplus of oil drove the price down to about $10 for a barrel.

This recent episode of business turmoil in Canada’s oil and gas industry has had more impact than most, because price volatility has been accompanied by major structural changes that have materially altered the makeup of the business. Everything began changing during the Focus Period: the industry’s mix of hydrocarbon products, the technology used to exploit them, the geographic locales of where to explore for them, the capital sources to finance them, the policies proposed to regulate them and the mar-kets to where they are shipped. Historically, the best analog for the magnitude of the changes happening today may be when the nascent industry shifted its activities from the oilfields of Petrolia, Ontario to the foot of Alberta’s Rocky Mountains in the early 1900s.

10 Themes to Follow

First Oil Sands ShipmentAthabasca River, 1914

Source: Glenbow Museum


The Industry TodayA hundred years later, Canada’s oil and gas

industry is the envy of the world. Thirty four million people are privileged to possess one of the largest hydrocarbon resource endowments of any nation, in the same league as major producers like the United States, Russia and Saudi Arabia. Yet how many oil and gas export-ing countries, large or small, can boast all the collective qualities that distinguishes Canada’s from any other? The answer, as you go down the check list, is “none.”

Consider that Canada’s oil and gas industry operates in an environment that has: a politi-cally stable democracy; a strong rule-of-law with respect for contracts; strict regulations that are getting stricter; one of the lowest corrup-tion ratings in the world; a highly experienced workforce; trillions of dollars of infrastructure built up over a century; a sophisticated spectrum of capital markets based on free enterprise; and a wide diversity of several thousand companies that produce anywhere from a few barrels a day to several hundred thousand, almost all head-quartered in one city (Calgary). With these

combined qualities, it’s no wonder that Canada is a prized destination for foreign capital seeking to minimize risk and maximize return.

Yet hubris is uncalled for. None of these ideals can be taken for granted in a capital intense business that relies heavily on foreign invest-ment and doesn’t always generate attractive returns. As our Industry Check-Up summed up the patient, “Health is never guaranteed, especially in today’s rapidly changing energy markets.”

Canada’s oil is increasingly subject to cost inflation, environmental pressure and social scrutiny. Our natural gas is overwhelmed by depressed prices caused by continental oversup-ply. Both energy commodities are increasingly suffering from discounted prices due to lack of access to global markets. Yes, Canada is a global leader with an enviable position, but further work must be done to reinforce all the positive attributes.

What’s at Stake?For a sense of scale, the most meaningful

number in this report is that the upstream oil and gas industry will continue to generate more than $100 billion per year of top-line sales for at least the next five years, notwithstanding a major commodity price collapse. Contrasted against other businesses, hydrocarbons are by far

the largest product-selling industry in Canada, larger than manufacturing automobiles. Impor-tantly, domestic oil and gas companies typically

reinvest every dollar of their cash flow plus more back into the ground. The multiplicative effect of these dollars circulating in Canada’s economy means that the stakes for ensuring a healthy oil and gas industry are high for all Canadians.

10 Themes to FollowNo doubt the next five years will be full of

surprises, and our Base Case forecast will appear too stable when subject to hindsight in 2015. Nevertheless, from what we’ve seen in the past, what we see today, and what our analysis por-

10 Themes to Follow

“The stakes for ensuring a healthyoil and gas industry are high

for all Canadians”

Upstream Oil & Gas

Autos Manufacturing

Forestry & Logging Wheat & Barley

Uranium0

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Rev

enue

s ($

C B

illio

ns)

A Comparison of Annual Revenues Major Canadian Product-Selling Industries

Source: Statistics Canada, CAPP, Canadian Wheat Board, Natural Re-sources Canada, Canadian Nuclear Association, ARC Financial Corp.


10 Themes to Follow

tends for the next five years, here are 10 impor-tant themes to follow.1. Commodity price volatility - Price is always the most important theme in this business and though forward market indications for oil and gas are pretty flat in our Base Case, volatility is guaranteed. Our sensitivity analysis on page 52 will help you quantify the swings.

2. Policies and regulation - Beside price, gov-ernment policies are the most influential force in energy. Changes to federal and provincial legislation had much impact over the past half decade. Fiscal, labour, environmental and export policies will be themes to follow closely.

3. Cost inflation - Rising costs challenged prof-itability and competitiveness last decade. Too much capital deployed too quickly bred infla-tion, a dynamic that will be an ongoing thematic challenge. Disciplined companies that innovate, migrate to high-quality resources and achieve economies of scale can be insulated.4. Oilier and oilier - Rising oil sands produc-tion in the face of flat natural gas output means Canada’s hydrocarbon mix is getting oilier and oiler. The increasing concentration to oil is fa-vourable as long as prices stay buoyant and costs are contained.5.Natural gas themes – Surplus gas from shale formations has led to depressed prices during the Focus Period. Exploring for the “fuel of the future” has become unviable for many Canadian producers. Looking ahead, supply declines, do-mestic demand growth and access to high-value Pacific markets will be active themes.6. Traditional investment - Uncharacteristi-cally, the traditional oil and gas segment did not spend all its cash flow most of the last decade. New technologies, vast resource plays and com-petitive fiscal regimes may now give companies incentive to invest more than their cash flow.7. Oil sands cash flow – The oil sands segment is expected to generate cash flow in excess of its currently planned project spending. However, the surplus may not persist. Developing new projects is a capital intense business vulnerable

to inflation; how oil sands companies spend their cash flow will affect the entire industry.8. Globalization - Since 2009, foreign interests have committed close to $18.5 billion into the industry, mostly into the oil sands. The shift from western capital providers to foreign sources is one of the biggest trends in the industry. More inflow is expected over the next five years, subject to predictable government policies. Paired against this large influx of offshore capi-tal is reciprocal momentum to open up exports of oil and gas beyond North America.9. More change and innovation in the field - Progressive oilfield service companies have led innovations that yield more productive, profit-able wells. The rapid pace of advancement and innovation in oil and gas fields will continue. From service companies, to producers, to capital providers, only those companies that are flexible to the changes will prosper.10. Profits will increase, but not always profit-ability - Focus on the latter. The dollar volume of the capital flow will continue to grow, driving the impression that the industry is making more money. But how well the industry copes with internal and external challenges will determine whether value is being created year-over-year, and whether more capital will be attracted to the business in the coming years and beyond the Forecast Period. One thing is certain: the indus-try’s fiscal pulse going forward will be volatile.

Source: Bloomberg, ARC Financial Corp.

0

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2000 2002 2004 2006 2008 2010

Nat

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Pric

e ($

C p

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J)

Oil

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per B

arre

l)

Daily Commodity PricesCrude Oil and Natural Gas

Focus Period

Gas Oil


Section 2

The Fiscal Pulse


The Fiscal Pulse of the Upstream Oil and Gas Economy

On the following page we show a simple model diagram of how capital flows cyclically into and out of the Canadian upstream oil and gas economy, or as we term it the fiscal pulse. The industry is segmented into two broad sectors: Exploration and Production (E&P) and Oilfield Services. Each sector is depicted as a black oval.

E&P companies determine where to explore for oil and gas. Oilfield service companies are contracted to do the physical prospecting, drill-ing and delivery to market. Once additional reserves are found, E&P companies manage the production and sale of their oil and gas from their newly added reserves. Capital flows through both the E&P and the Oilfield Service sectors, which work closely together to create value for stakeholders.

The mechanics of the accompanying capital flow diagrams represent an accounting of the dollars and product volumes flowing through the industry. Production Volumes are multi-plied by Commodity Prices to yield gross E&P Revenue . Interest and General and Administra-tive (G&A) expenses are deducted, as are Royal-ties and Taxes . Royalties are mostly depen-dent on commodity prices, but well depth and production ouput are also major determinants. Taxes are mostly a function of net income, owed both federally and provincially.

Managing and operating the base of produc-tion is labour, capital and energy intensive. Op-erating Expenditures have fixed and variable

components that adapt to commodity prices.A large fraction of Cash Flow is typically

allocated to reinvestment; this is the CAPEX pool . To leverage capital and gain cycle momentum, the CAPEX pool is supplemented with Debt and Equity. During periods of healthy cash flow, debt may be paid down and equity repurchased through Buybacks. Dividends and Distributions, and changes to working capital account for any remaining cash flow.

A certain amount of capital also ‘leaks’ out of the system as multi-national companies seek to repatriate their Canadian-earned cash flow or reinvest it abroad. This dynamic is difficult to capture and is represented in Foreign Investment and Capital Outflow. Counterbalancing leakage, Foreign Joint Venture ( JV) Capital is a new and significant stream of funding that has emerged since 2009, especially from Asia.

Capital in the domestic CAPEX pool can be rationed a number of different ways: oil versus natural gas drilling, exploration versus develop-ment, traditional versus oil sands, and so on.

In our chart, we broadly segment capital spending into two: Exploration and Development and Land.

Oilfield Services Revenue is largely depen-dent on domestic E&P spending, over 50% of which is typically allocated to drilling. Note that not all E&P capital spending goes to the oilfield service sector. There many Other peripheral ex-penditures for goods and services that percolate into the Canadian economy.

Drilling and Completions yield oil and gas Reserve Additions , which are often placed into production as soon as is technically and finan-cially feasible. Productive capacity – the ability of a reservoir to produce hydrocarbons – de-clines over time, similar to diminishing product inventory. To replenish depleting reserves, the entire cycle of capital flow starts all over again.

How well Canada’s oil and gas capital cycle performs in the face of many internal and external forces determines profitability of the industry. Delivering stable, long-term financial returns has always been challenging amidst a backdrop of uncertain commodity prices, competitive challenges, constrained labour pools, geologic risk, and cost inflation.

Availability of high quality statistics at points around our diagram enable us to model capital flows with a reasonable degree of confidence; enough to determine the magnitude and direc-tion of the most important economic trends and financial measures.

Availability of high quality statisticsenable us to model capital flows.


The Fiscal Pulse by the Numbers

All Segments 2010(Traditional Oil and Gas + Oil Sands)

5.7 MMBOE/d

$47.0

$4.6 $4.1

$12.5

1,467 MMBOEc

12,100 wellse

$45.1

$4.3

All dollar values in billions ofCanadian dollars unless otherwise noted.

a West Texas Intermediateb AECO Hubc Established, excluding oil sandsd Value committed in 2010e Wells drilled (rig-release)

$US 79.50/Ba

$3.80/GJb

$100.0

$29.5

$11.0

$19.7

$7.8d

$3.8



4.2 MMBOE/d

$US 79.50/Ba

$3.80/GJb

$30.2 $15.7

$3.4 $3.0

$9.2

$62.9 $28.9

a West Texas Intermediateb AECO Hubc Established reserves, excluding oil sandseWells drilled (rig-release)


Oil and Gas 2010(Excluding Oil Sands)

1,467 MMBOEc

$3.7

10,900 wellse



$13.0$13.8

$1.2$1.1

$3.3

$37.11.5 MMBOE/d

Bitumen: $59.00/Ba

Synthetic: $80.50/Bb

$16.2

a Sourced from ERCBb Sourced from Canadian Oil Sands Annual Report


Oil Sands 2010(Excluding Traditional Oil and Gas)

$0.1


Major Trends and Issues Around the Fiscal Pulse

Major Trends and IssuesIn the context of the Focus and Forecast Peri-

ods, there are many qualitative and quantitative findings that can be gleaned from the numbers that CAPP collects and records. Summarized below are some of our findings loosely grouped to follow the capital flow diagram on page 9.

Price, Production and Revenue

Commodity prices have been exceptionally volatile — Over the past six years, oil prices have ranged from a high of $US 145/B at the peak of the commodity bull run, down to $US 32/B during the Great Recession. The run up to almost $US 150/B between 2006 and 2008 delivered tremendous revenue, cash flow, royal-ties and taxes. However, rising commodity prices quickly pulled up the industry’s costs too – a harmful and stubborn artifact that was a major contributor to poor profitability and disadvan-taged competitiveness during the subsequent downturn in 2009. Severe weather events and production declines prior to the shale gas phe-nomenon contributed to gas price volatility.

A rising Canadian dollar diminished the value of exports at a vulnerable time — Back in the early 2000s, some economists were talk-ing about a fifty-cent Canadian dollar as the Loonie continued a 10-year downward descent. It didn’t happen. By 2003, the commodities

boom, combined with a weakening US dol-lar, contributed to an aggressive ascent of the Canadian dollar toward US parity, interrupted only by the Financial Crisis. Because oil and gas exports are sold in US dollars, the strengthening of the Canadian dollar by 25% during the Focus Period materially weakened realized commod-ity prices for domestic companies, and impeded profitability during a vulnerable period of policy shocks and competitive pressures from US shale gas producers. Now, dollar parity appears to be the new norm to which Canadian producers are adjusting. In the Forecast Period, exchange rates from the currency futures market have been used to convert U.S. denominated commodity prices into Canadian dollars.

Natural gas production is declining, but has potential to grow again — It took a 100 years and almost 200,000 gas wells to grow Canada’s natural gas output to its peak level of 17.3 Bcf/day in 2001. Over the course of the last decade production has fallen by 2.8 Bcf/d, mostly dur-ing the Focus Period, and is expected to continue falling by another 1.2 Bcf/d before leveling out in 2014. Low prices, continental competition, distal markets and high development costs have exacted a heavy toll on the investment needed to sustain output. On the positive side, a migration of drilling activity to prolific, unconventional resource plays in northeastern B.C. and parts of Alberta has the potential to arrest and even re-verse the natural gas production decline. Higher prices and access to pan-Pacific growth markets from Canada’s west coast will be some of the many determining factors governing future natural gas output capacity.

Falling natural gas liquids production may be arrested too — Natural gas production in Alberta also yields associated liquids such as ethane and butane. Because much of the decline in natural gas output has happened in Alberta, the production of associated natural gas liquids (NGLs) has also dropped off. Over the Focus Period, NGL volumes fell by 12%. However, the decline may be arrested, because the industry is migrating back to Alberta’s liquids-rich plays with renewed vigor. Two reasons account for the drilling shift: NGL prices are attractive in

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Canada and the May 2010 revisions to Alberta’s New Royalty Framework have made it eco-nomically viable to explore for the commodities using new horizontal drilling and completion technologies.

Oil sands output is growing and filling in for natural gas declines — Although natural gas volumes have fallen by 15% during the Focus Period, growing production from the oil sands is picking up the lost share of output on a barrel-of-oil-equivalent basis and more than filling in the revenue shortfall. Oil sands production (bitumen and synthetic crude oil) will continue to grow into the Forecast Period and by 2015 is expected to reach 2.1 MMB/d – up 600,000 B/d from 2010 levels.

Growing oil output is also shifting the production mix — While the backfilling of declining natural gas volumes with oil sands production has mitigated revenue loss, the increasing bias toward oil exploration and development amplifies the concentration toward the commodity. By 2015, Canada’s hydrocarbon mix by volume will be biased 63% toward oil (conventional plus oil sands) and 37% to natural gas. That’s a big shift from a more balanced 51% oil and 49% gas in 2005. But that’s not all. Due to higher oil prices and lower natural gas prices the concentration is more pronounced from a revenue measure: by 2012 over 80% of the industry’s revenue will come from oil, and less

than 20% from natural gas.

Canada’s oil and gas industry will generate more than $100 billion a year in sales — Af-ter rising to a $145 billion peak in 2008, then dropping precipitously to $89 billion during the 2009 financial crisis, the annual sales of all up-stream hydrocarbon products will exceed $100 billion again in 2011. A revenue rate in excess of $100 billion per year is expected to be sustain-able through the five-year Forecast Period, but the progressively greater concentration toward oil will make the industry’s income stream – and consequently the governments’ tax and royalty takes – much more sensitive to domestic and global factors affecting petroleum commodities.

Alberta remains the dominant contribu-tor to the industry — Despite growth in the output of hydrocarbons from B.C. and Sas-katchewan, and the shrinkage in Alberta natural gas volumes, over 75% of Canada’s hydrocarbon production still comes from Alberta. The contri-bution from Alberta is expected to remain fairly steady over the Forecast Period.

Policy, Taxes and Royalties

Policy implementations have been a major influence on the industry — Three major policy events punctuated the Focus Period. On October 31, 2006, the federal government changed its stance on income trusts. Having proliferated during the first half of the decade to the point of representing 15% of WCSB production volume, income trusts – also known as royalty trusts – were legislated to be phased out by January 1st, 2011.

In late 2007 the Alberta government intro-duced a more burdensome fiscal regime under the New Royalty Framework (NRF), which was subsequently implemented on January 1, 2009. Both the federal and provincial policy imple-mentations had far-reaching effects, triggering substantial uncertainty on the industry’s operat-ing structure and competitiveness, especially the ability of companies to access investment capital. The third major policy event was the restruc-


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Crude Oil and Liquids

Source: CAPP, ARC Financial Corp.

ForecastFocus


turing of the NRF in May, 2010. The Alberta government worked with industry to address uncompetitive elements within the NRF and provided incentives for the industry to use new technologies in emerging resource plays.

By the end of the Focus Period, most oil and gas income trusts had converted into corpora-tions and the restructured NRF had become a catalyst for renewed investment back into Alberta.

The tax take fell hard in 2009, but is re-bounding — Relative to the boom years of 2005 to 2008, when the industry paid on aver-age over $6.0 billion per year in current taxes, the government’s tax take shrunk by 40% during the Financial Crisis and recession of 2009. The reduction in federal tax rates from 26% to 18% over the Focus Period, signalled a pro-business policy that has helped the competitiveness of all industries, including oil and gas. A rebound in current taxes to between $4.0 billion and $5.0 billion per year is expected over the Forecast Pe-riod, but won’t approach the extraordinary $6.6 billion peak recorded in 2007.

Crown royalties are rebounding too — In the 1990s, crown royalties averaged a fairly consistent $3.0 billion to $4.0 billion per year. Because royalties are predominantly a function of commodity price, the bull run in oil and gas prices during the 2000s rapidly pushed up the provincial governments’ take to a stunning $19.0

billion by 2008, 67% of which was realized by Alberta. Despite the Alberta government’s New Royalty Framework, which was supposed to capture even more royalties on a unit of pro-duction, the economic slowdown in 2009 cut the royalty take by more than half. A gradual rebound in total crown royalties, to between $10.0 billion and $15.0 billion is expected in the Forecast Period, however due to lesser natural gas volumes and weak gas prices, the government’s royalty take over the next five years will be much more leveraged to oil prices and oil sands production.

Costs, Cash Flow and Profitability

Operating costs susceptible to inflation — Prior to the start of the Focus Period, operating costs in the upstream oil and gas industry were beginning to inflate, with labour and energy input costs being the principal drivers. Momen-tum carried traditional operating costs from $7.70/BOE to an estimated $10.20/BOE be-tween 2006 and 2010. In the oil sands, the cost inflation was also acute, jumping from $19.60/BOE to $25.50/BOE. Though it has moderated, inflation is still potentially problematic. On the natural gas side of the business, the amortization of fixed charges into declining volumes will con-tribute to higher unit costs. Upward wage pres-sure is potentially threatening to all segments of the industry, and increasingly likely if oil prices continue to rise. Nevertheless, a compounding rate of cost inflation is unsustainable, because ultimately profitability and investment are the regulating mechanisms in capital flow.

Over the Forecast Period we use a modest cost inflation of 2% per year as a base assumption for traditional oil and gas, and 5% for the oil sands. However, the industry’s investment pace will dictate whether inflation will be higher or lower.

General and administrative costs have risen over two-fold — A long-standing rule-of-thumb for estimating the burden of office leases, professional salaries and other general and administrative costs used to be $1.00 for


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Source: Statistics Canada, ARC Financial Corp.

ForecastFocus


every BOE produced. By 2005, G&A costs had risen 70% to $1.70/BOE, on their way to a peak of $2.75/BOE in 2009. The Great Recession arrested the inflationary pressures, but the am-plified per-unit G&A burden – now tracking an estimated $2.25/BOE – remains a competitive burden, especially for smaller producers.

Finding and development (F&D) costs have moderated after peaking in 2007 — For over a decade, between 1996 and 2007, CAPP data showed that the cost of finding and developing an additional unit of oil and gas reserves was in-creasing by an average of 8% per year. There are many ways to gauge F&D costs, but regardless of how the metric is defined, the unsustainable, long-term uptrend was common to all calcula-tions. Also common to the calculus was the meaningful disruption in the decade-long esca-lation, when in 2009 surplus oilfield and drilling capacity contributed to a 25% to 35% drop in service costs. Other factors also contributed to F&D deflation, including better productivity, greater economies of scale accruing from inno-vation and the shift to resource plays. Looking ahead into the Forecast Period, containing F&D costs will have to be a necessary discipline if competitiveness is to be maintained.

Labour will be an ongoing challenge – In late 2008, a peak of 156,000 workers were em-ployed in Alberta’s forestry, mining, fishing and oil and gas industries, with most of the workers

in the latter. Like everywhere, jobs were lost due to the financial crisis, and the industry’s employ-ment figures dropped sharply through 2009. But unlike other regions, Alberta’s fortunes turned relatively quickly, piggybacking on favorable economics for finding and developing conven-tional oil and oil sands. A tightening labour pool is a major factor contributing to inflation. How the industry accesses and manages labour over the next five years will determine whether our report’s inflation expectations are in-line or too conservative.

Pipeline tolls took a toll on the natural gas business – Transportation costs for delivering western natural gas to eastern markets were very stable for almost a decade. Unit costs of deliver-

ing gas from the Alberta border to TransCan-ada’s Eastern Zone in Ontario used to average $1.00/GJ when the pipeline was operating at or near capacity. However, lower-cost US shale gas proximal to northeast markets has been a major competitive force in pushing back WCSB prod-uct flow. Declining western production meant that a unit of natural gas headed east had to absorb a greater proportion of the fixed costs of the regulated pipelines. Transportation tolls for natural gas on the TransCanada Mainline rose to $1.60/GJ by 2010 and were threatening to go higher. This contentious issue of rising pipeline tolls diminished the competitiveness of WCSB gas in eastern markets and was in the process of being addressed by TransCanada Corporation and producers in early 2011. Negotiations were ongoing at time of writing this report.


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Source: Statistics Canada, ARC Financial Corp.

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Source:TransCanada Corporation, ARC Financial Corp.

Focus Period


Relative netbacks between oil and gas have widened dramatically — On a BOE basis, the industry realized similar netbacks (cash margins) from traditional crude oil and natural gas up until 2005. Further, variability in the netbacks of both commodities tracked each other closely, except during extraneous pricing events such as hurricanes or geopolitical incidents. By 2006, a sustained profitability gap started to form that began to favour crude oil over natural gas. Divergence in the price of the two commodi-ties was the biggest reason for the departure in

profitability. At the end of the Focus Period, the average netback from producing dry natural gas in the WCSB was almost down to zero, while

conventional oil maintained a $18.00/BOE cash margin advantage. The inequality in netbacks between oil and gas explains why the industry began progressively shifting its investment focus toward oil and liquids-rich natural gas projects during the Focus Period.

Capital Expenditures and Markets

Capital expenditures will match or exceed cash flow — During the early part of the last decade, the industry’s overall capital expen-ditures characteristically moved in sync with year-over-year variations in cash flow, though over the last five years the industry uncharac-teristically did not reinvest all of its cash flow back into the ground. As well, oil sands projects captured proportionally more cash flow dollars, especially in the flush years between 2005 and 2008 when total capital expenditures averaged $50 billion per year.

Between 2011 and 2015, we expect a total of $275 billion to be invested; $91 billion toward oil sands and $184 billion toward oil and gas. Importantly, the traditional side of the business is expected to reinvest all of its cash flow and augment it with debt, equity and more foreign joint venture capital.

Debt and equity markets barely paused for the Financial Crisis — Canada’s upstream oil and gas industry has always relied on debt and

equity to augment the reinvestment of cash flow into capital expenditures. Availability of capital typically varies with economic cycles, commod-ity prices and profitability. It’s no surprise then that the Focus Period witnessed the richest years of sustained access to capital markets in the history of the industry. A fairly consistent $15 billion per year of debt and equity was raised with the exception of the record-breaking year 2007, when over $25 billion poured into corpo-rate treasuries. Interestingly, the financial crisis and Great Recession didn’t crimp the ability of the industry to access markets for more than a few months; in fact, total debt plus equity raised in 2009 surpassed 2008. Based on expected cash flows, the amount of capital available to the industry each year in the Forecast Period is expected to remain robust and relatively stable. However, as to be expected, the incoming capital will be more selective than in the past, discrimi-nating in favour of those companies principally producing oil over natural gas — at least until the profitability gap at the wellhead narrows.

Asia is becoming a major source of “un-conventional” capital — The first major Asian investment into the Canadian oil and gas industry was in 1978 when the Japan Petro-leum Exploration Company ( JAPEX) forayed into Alberta through Japan Canada Oil Sands Limited ( JACOS). But it wasn’t until 30 years later that Asian participation in Canada’s hy-drocarbon riches would go from a toehold to a


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material source of capital. In the period between August 2009 and March 2011 a total of $18.5 billion of foreign capital, mainly from Asia, was infused into the Canadian oil and gas economy. Just over half of the total money, about 55%, tar-geted the oil sands. However, the last three deals and the largest of all the deals were directed to companies targeting natural gas resource plays. A large portion of the foreign money, coming from China, South Korea, Thailand and Japan, has been committed in the form of funding joint venture partnerships – an unconventional source of external capital that supplements traditional debt and equity. Of course, joint venture funding in the industry is nothing new, but the mag-nitude of the investments and the exogenous source of the capital is a trend that is expected to continue into the Forecast Period.

Oilfield Trends

Resource plays are the new Klondike, at-tracting record land sales — Attractive pric-ing for natural gas between 2005 and 2008, combined with the rapid uptake in horizontal drilling and hydraulic fracturing, led to aggres-sive land sales in northeastern B.C. where high-quality, large-scale unconventional gas resources were staked. During the shale gas frenzy, the B.C. government realized peak land sales in 2008 totaling $2.7 billion, two-and-a-half times greater than the province’s best year. A year

earlier in 2007, Alberta’s land sales (excluding oil sands) had fallen by 50%, mostly due to the burden and uncertainty brought on by the New Royalty Framework. By mid-2010 the tables turned. Land sales in B.C. retreated back to normal levels, while the race to claim known resource plays bearing light oil, also exploitable through new drilling and fracturing techniques, brought the action back to Alberta. In 2010, the Alberta government realized a record $2.4 billion in land bonuses. Klondike-like land sale activity, which was also experienced during the oil sands boom of 2005, is not expected to con-tinue at its current pace into the Forecast Period, but should remain robust in oil-rich Alberta and Saskatchewan as long as oil prices remain solidly above $80.00/B.

A major technology shift is in play — Hori-zontal drilling is nothing new and was first em-braced meaningfully in the early 1990s. For the most part, the technology only suited a niche market at the time with the substantially higher cost of drilling being unjustifiable for broad ap-plication. Consequently, during the subsequent 15 years, only a steady one-in-ten Canadian wells was drilled and completed horizontally. But rising commodity prices in conjunction with rapid improvements in digital sensing equipment, instrumentation, and innovations in multi-stage hydraulic fracturing were all catalysts for a change in the entrenched drill-ing paradigm. A new era of horizontal drilling

emerged in 2007, and in three short years 40% of all wells drilled in Canada had horizontal trajectories. This trend shows no signs of abate-ment as the technology improves on a monthly basis and continues to unlock oil and gas resources that were once deemed too expensive to exploit.

Horizontal wells are also being drilled deeper and with longer laterals — The char-acter shift of drilling in Western Canada is not just going from vertical to horizontal. On aver-age, the horizontal wells that are being drilled are getting progressively deeper and longer. Single and multiple lateral segments have been gradually extended by about 500 meters over the last five years to further enhance productivity. Because well costs rise exponentially with depth and length, this sub-trend amplifies the highly visible increase in average well costs, which is most pronounced in northeastern B.C. Individ-ual well costs across the WCSB have increased almost 100% through the Focus Period.

The well count is being recalibrated — The major shift toward more prolific, deeper and more capital intense horizontally-drilled wells means that the annual well count – that trusty barometer of industry activity – is no longer calibrated to the past. Fewer wells are com-manding a greater share of the total CAPEX budget, but are also yielding at least as much production output as multiple vertical wells.



Perhaps the most dramatic change in drilling character and well count is noted in the shallow gas region of southeastern Alberta, where the annual well count has gone from over 9,000 in 2005 down to 1,000 at the end of the Focus Pe-riod. Across the industry, a well count of 20,000 was considered robust and active only three or four years ago. Looking into the Forecast Period, a well count of 12,000 will signal good health on the industry’s charts.

Oilfield equipment and service sector is ex-periencing big changes — Oilfield service and equipment providers went from boom to bust, experiencing the extremes of equipment short-ages and overcapacity in the span of two short years during the Focus Period. The oilfield service sector feeds directly off the capital expenditures of the producers, so when investment into oil and gas exploration (traditional oil and gas excluding oil sands) dropped from $36 billion in 2008 to $22 billion in 2009, the pain was almost immediate. Rig utilizations tracked under 30% for most of 2009, levels not seen since the 1980s. In response, the rig fleet shrank going into 2010, though not enough to bring capacity utilization back up to historically acceptable levels. Not all segments of the service sector have suffered during the downturn. For example, companies offering the specialized services and equipment for hydraulic fracturing have fared well, record-ing near 100% utilization toward the end of the Focus Period. Drilling activity is slowly recover-

ing as the industry migrates to oil plays, but higher capital expenditures and well counts are insufficient gauges of success for all oilfield ser-vice companies. Going forward, the successful beneficiaries of change in this specialized sector will be those that have innovative management, quality equipment and skilled manpower that are all attuned to the new exploration and devel-opment requirements of resource plays.

The Bottom Line

Profitability in the industry will remain volatile — At the industry level, making money in Canada’s upstream oil and gas industry has been a very long tale of recurrring fitness and illness. Rising commodity prices have generally contributed to a fit industry with short win-dows of surplus returns, while slumps have led to longer periods of marginal and sometimes negative profitability. Even so, commodity prices and profitability do not necessarily correlate. For example, during the Focus Period, the peak of profitability – as measured by Return on Capital Employed (ROCE) and Return on Equity (ROE) – was in 2005, not 2008 when oil and gas prices spiked to their highs. Rising costs through those years quickly diminished profit-ability despite high commodity prices. ROCE in 2005 crested at a healthy 16.7% and dropped to a weak pulsed 3.5% in 2009. Assumptions that feed into the Forecast Period suggest the in-

dustry should realize a ROCE of between 6.0% and 8.0%, a range that is reflective of long-term returns in the business. However, history shows that achieving a sustained state of stable profit-ability over the next five years is unlikely due to price volatility and relentless challenges.

Detailed Examination

Charts displayed Section 3 follow in detail the key variables and trends that track capital flow in the industry. The checkpoint numbers on page 17 are repeated on the title line of each page so that you may follow the progression of the charts around the fiscal pulse diagram.


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Section 3

Detailed Examination


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Canadian Upstream Hydrocarbon ProductionAnnual Volume in Millions of BOE per Day by Type

Canada’s total oil and gas production will be resuming its growth path over the next five years, with output from the oil sands delivering most of the new volume.

The first thing that’s noticeable about Canada’s hydrocarbon production is that overall output during the Focus Pe-riod fell appreciably, by about 6% from the 2007 peak. In fact, the production rollover that started in 2008 was the first major dip since the energy crisis in the early 1970s. Looking ahead, volume growth is expected to return during the Forecast Period, but mostly on the shoul-ders of increasing oil sands output.

In 2005, natural gas represented 49% of the country’s hydrocarbon produc-tion. Although natural gas production is expected to level out, its volume con-tribution is projected to only compose 37% of the mix by 2015.

And that’s the other observation that heralds big change in the industry: a shifting product mix. Declining natural gas output, due to competitive pressures from US shale gas, is being offset by a growing oil sands fraction. More oil and liquids from resource plays may shake up the mix even more.

So, the Canadian upstream oil and gas business is becoming progressively “oilier.” By 2015, traditional oil plus oil sands are expected to contribute 63%. Within the oil sands, bitumen will constitute an increasing fraction due to domestic upgrading constraints.


ForecastFocus Period

Bitumen

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Canada’s Hydrocarbon Production by Province

AlbertaAnnual Volume in MMBOE per Day by Type

Alberta remains the dominant hydro-carbon producer representing 75% of the country’s output. When the province is viewed separately, its increasing bias to oil sands becomes very apparent.

During the Focus Period, the industry launched into British Columbia’s Mont-ney and Horn River resource plays, and positioned them for expansion. Ongoing investment into these regions is expected to ramp up growth. B.C. is prone to natural gas, so its revenue, royalty and tax potential will be muted compared to Alberta, Saskatchewan and the Maritimes, all of which have much larger oil fractions.

Saskatchewan is oil-weighted with potentially understated upside in re-source plays like the Bakken. Though its oil output is forecast to be level, prospective plays that are conducive to horizontal drilling and completion may yield unexpected growth. Resource plays in Alberta and Manitoba’s oil may also contribute surprise volumes.

Production from the rest of Canada mostly comes from the Maritimes. Newfoundland produces most of the oil, which is in decline, though some offset is expected in 2017, when Hebron comes on-line. Nova Scotia composes the bulk of non-WCSB gas production.

British ColumbiaAnnual Volume in MMBOE per Day by Type

Rest of Canada1

Annual Volume in MMBOE per Day by Type


SaskatchewanAnnual Volume in MMBOE per Day by Type

ForecastFocus ForecastFocus

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NaturalGas

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Note: Vertical scale difference.


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West Texas Intermediate (WTI) Crude Oil Prices

Annual Average WTI Crude Oil PricesHistorical Prices to 2010; NYMEX Futures Prices to 2015 (as of Dec. 31, 2010)

Oil prices tend to be volatile and are influenced by many factors such as the global economy, currency fluc-tuations, inventory levels, supply and demand trends, geopolitical forces and demographic issues. The volatility was acute over the past five years, especially between 2008 and 2010.

At the beginning of the Focus Period, global economic growth was exception-ally strong in all the major economies, but especially so in rapidly industrial-izing, emerging economies, notably China. Supply and demand began to tighten early in the Focus Period ultimately taking the price of oil to its momentary peak of $US 145.00/B in mid-2008. But soon after the financial crisis, at the trough of the Great Reces-sion in February 2009, oil consumption retreated by 2.0% and prices collapsed to $US 32.00/B.

West Texas Intermediate (WTI) is the benchmark for pricing grades of North American oil. In our chart, daily spot prices have been averaged over the course of each year to 2010.

New York Mercantile Exchange (NYMEX) oil futures prices were used for the Forecast Period and represent the Base Case price projection. Sensitivity tables on page 53 accomodate the effect of inevitable price volatility.

Oil prices exhibited extreme volatility during the Focus Period. Although futuresprices are flat on the NYMEX curve, volatility should be expected.

Source: Bloomberg, National Bank of Canada, ARC Financial Corp. ForecastFocus Period


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Canadian Oil Prices and Differentials

Edmonton Light Oil PricesHistorical and Forecast Average Prices

Edmonton Light is the benchmark Canadian light sweet crude oil that has similar high-quality characteristics as WTI. Because of the close proximity to the US market, the price of Edmonton Light tends to mimic that of WTI. Currency exchange, transportation costs, relative quality and regional demand are among the factors that account for the price differ-entials between the two, however Edmonton light is not readily traded in a futures market. As such, forward Edmonton Light prices in the Forecast Period have been derived from WTI futures using longstanding, funda-mental relationships. Assumptions for forward Canadian dollar exchange rates were taken from the currency futures market.

Heavy and Light Oil Price DifferentialsAbsolute Differentials and Heavy-to-Light Percentage

Heavier oils trade at a discount to the more desirable light and sweet crudes. Historically, heavy oil (benchmarked at 900kg/m3) has traded between 60% and 80% of the value of Edmonton Light. Many factors contribute to the discount, including supply levels and access to refinery capacity. Constrained access to the more limited and complex refineries needed for processing heavy oils increases the discount. Favorable refinery demand and pipeline access during the Focus Period, narrowed the dis-count to an unusally narrow 85% in 2009. Over time, access to refineries is expected to become more competitive due to higher output; as such, the heavy oil price discount is expected to migrate back to about 30%.

Source: Bloomberg, ARC Financial Corp. Source: ERCB, ARC Financial Corp. ForecastFocus Period ForecastFocus Period


0

1

2

3

4

5

6

7

8

9

10

1990 1995 2000 2005 2010 2015

Pric

e ($

C p

er M

cf)

Natural Gas Prices

Alberta Benchmark Natural Gas PricesHistorical Prices to 2010; Prices Derived from AECO Futures Prices to 2015

In the absence of regional supply and demand imbalances, Canadian natural gas prices are closely correlated to US benchmarks after adjusting for currency exchange and pipeline transport costs.

During the Focus Period, AECO natural gas prices closely tracked those at Henry Hub in Louisiana. The peak year was 2005, when damage inflicted by hurricanes Rita and Katrina helped drive a tight market to an annual aver-age of $8.60/Mcf. Four years later, the Great Recession and surplus supply from prolific shale gas wells pushed the average price down to below $4.00/Mcf.

Oversupply from shale gas continued to be a price antagonist into 2010, at a time when oil prices were recovering handsomely.

For the Forecast Period, Base Case natural gas prices were derived from the AECO futures curve dated Decem-ber 31, 2010. The muted price outlook reflects the market’s expectation of continuing robust shale gas production.

At time of writing, four North Amer-ican LNG export terminals had been announced, most notably the Kitimat project on the B.C. coast. Such projects will potentially expose Canadian gas to higher world prices, but not likely before the end of the Forecast Period.

Hurricane damage and tight supply drove natural gas prices to a 2005 peak,but economic recession and oversupply have since muted price appreciation.

Source: Bloomberg, National Bank of Canada, ARC Financial Corp. ForecastFocus Period


0.00

0.25

0.50

0.75

1.00

1.25

1.50

1.75

1990 1995 2000 2005 2010 2015

Pric

e ($

US

per M

MB

tu)

0

1

2

3

4

5

6

7

8

9

10

1990 1995 2000 2005 2010 2015

Pric

e ($

US

per M

MB

tu)

Natural Gas Prices and Differentials

Annual Henry Hub Natural Gas PricesHistorical and Forecast Average Prices

Natural gas in North America is a continental commodity delivered through an expansive pipeline system that connects major supply and demand regions across Canada and the United States. Henry Hub in Louisiana is the primary benchmark transaction point on the system.

The broad, increasing price trend between 1999 and 2005 was largely due to tightening supply, increasingly amplified each year by seasonal demand peaks in winter and summer. A rapid ramp up in shale gas production during the latter half of the Focus Period broke the long-term uptrend. Like oil prices, NYMEX natural gas futures prices are used in the Forecast Period and represent our Base Case price projection.

US-Canadian Natural Gas Price DifferentialsAnnual Average (Henry Hub - AECO) Price Differentials

Source: Bloomberg, National Bank of Canada, ARC Financial Corp. Source: Bloomberg, National Bank of Canada, ARC Financial Corp. ForecastFocus Period ForecastFocus Period

When cross border fundamentals are stable, the difference between US and Canadian gas prices mostly reflects the transportation toll cost (in US dollars) between hubs. However, seasonalality, regional imbalances and the complexities of continental pipeline flows also contribute to price differences. During the Focus Period, Alberta’s AECO price traded mostly at 85% of the price at Henry Hub, in-line with the long-term average. For the Forecast Period, implied forward differentials are taken from the futures market as of December 31, 2010. The result of current toll negotiations between TransCanada Corp. and upstream producers will determine whether or not forecasted price differentials are realistic.


Canada exports about 60% of the natural gas it produces, all of it to the United States. In 2010, the value of those cross-border sales was estimated to be about $15.0 billion, sold at low prices, because of oversupply and no option to export to higher paying global customers.

As mentioned, Canadian natural gas prices sympathetically track those set at Henry Hub in Louisiana. To put North American prices in context, our chart shows the difference between Henry Hub and the market at the National Balancing Point (NBP) in the United Kingdom – a reasonable proxy for world prices. Positive values above the zero line indicate that North American prices garner a premium to world mar-kets; negative represents a discount.

North America was consistently a premium priced market up to 2005. During the Focus Period significant dis-counts began to present, especially after 2008, when shale gas overwhelmed sup-ply. Today a $5.00/MMBtu differential to world markets represents a steep 55% discount. The lack of coastal send-out facilities is crimping Canada’s ability to capture the best prices for its natural gas exports. During the Focus Period, North American natural gas prices

began to trade at a significant discount to world markets.

-8

-6

-4

-2

0

2

4

6

8

10

2000 2002 2004 2006 2008 2010

$US

per M

MBt

uWorld-US Natural Gas Price Differentials

Monthly Average (Henry Hub - NBP) Price Differentials

Natural Gas Prices in a World Context

Focus Period

Discount to World Prices

Premium to World Prices



North American oil has historically garnered a small price premium rela-tive to international markets. But like natural gas, price discounts for US and Canadian oil began to show during the Focus Period.

Our chart shows the monthly average price difference between the US bench-mark WTI and the comparable North Sea Brent crude. In early 2011, a wide differential between $US 10.00/B and $US 15.00/B emerged. For Canadian oil producers, this large discount implies the forfeiture of significant revenue, which amounts to billions of lost dollars if sustained.

Like natural gas, the issue is one of domestic oversupply with no outlet. WTI is priced at Cushing, Oklahoma, where storage facilities are well stocked to near record levels at time of writing. Growing Canadian and US oil produc-tion could make the situation last, or at least recur. Ultimately, Canadian oil exports that are confined to a land-locked US market need to gain access to seafaring destinations. The Pacific Ocean is an ideal gateway for diversify-ing into energy growth markets around the world and ensuring that the export value of Canada’s oil and natural gas resources are not discounted.

Like natural gas, the issue of crude oil price discounts is one of domestic oversupply with no outlet.

-15

-10

-5

0

5

10

2000 2002 2004 2006 2008 2010

$US

per B

arre

lWorld-US Crude Oil Price Differentials Monthly Average (WTI - Brent) Price Differentials

Crude Oil Prices in a World Context

Focus Period

Premium to World Prices


Discount to World Prices


0

20

40

60

80

100

120

140

160

1990 1995 2000 2005 2010 2015

Rev

enue

($C

Bill

ions

)

Canadian Upstream Industry Revenue

Canadian Upstream Hydrocarbon Revenue Annual Dollar Amount by Product Type

Oil and gas companies produce many different hydrocarbon products of varying type and quality. Eight dif-ferent product classifications are used to estimate the aggregate upstream revenue: light and medium oil, heavy oil, bitumen, synthetic crude oil (SCO), natural gas liquids (NGLs), pentanes, condensates and natural gas. To derive this chart, each commodity’s production volume is multiplied by the average an-nual price that was, or is expected to be realized by all producers.

The sharp rise in commodity prices beginning in 2000 catapulted upstream revenue to over $60 billion per year – over twice what was being realized for most of the 1990s. By 2005, total rev-enue breached the $100 billion mark .

Under the Base Case price scenario, annual revenue of above $100 billion should sustain and grow to almost $130 billion by 2015 (in the absence of a seri-ous commodity price decline). Growth in oil sands production combined with a strong forward oil price curve is respon-sible for the robust projection.

The industry’s revenue is on a path to become 80% reliant on oil by 2015, which is a major departure from the more balanced 55/45 oil-to-gas sales mix in the middle of last decade.

Strong oil prices and growth in oil sands output will drive the industry’s upstream revenue to over $100 billion per year again.


OilSands


NaturalGas



-

20

40

60

80

100

120

1990 1995 2000 2005 2010 2015

Rev

enue

($C

Bill

ions

)

0

5

10

15

20

25

1990 1995 2000 2005 2010 2015

Rev

enue

($C

Bill

ions

)

0

5

10

15

20

25

1990 1995 2000 2005 2010 2015

Rev

enue

($C

Bill

ions

)

0

5

10

15

20

25

1990 1995 2000 2005 2010 2015

Rev

enue

($C

Bill

ions

)

Canadian Upstream Industry Revenue by Province

AlbertaHydrocarbon Revenue by Product Type

Industry revenue is dominantly gen-erated in Alberta where an estimated $86 billion of the industry’s $115 billion in 2011 sales will originate.

Going forward, hydrocarbon sales originating from Alberta and British Columbia are expected to grow the fast-est. Most noticeable is Alberta, where rising oil sands output and a strong forward price curve combine to grow the top line by over 30% in five years.

Revenue growth in British Columbia will piggyback on rising natural gas pro-duction and a price curve that is mildly trending upward.

Saskatchewan will derive the over-whelming majority of its hydrocarbon revenue from crude oil. Exploration and development of tight oil plays like the Bakken may yield higher-than-expected production volumes, but our Base Case conservatively assumes steady output that will still yield respectable revenues of $12 billion each year over the Forecast Period.

In the rest of Canada, oil revenue from Newfoundland is expected to fall over the Forecast Period due to net pro-duction declines. Natural gas revenue from offshore Nova Scotia will contrib-ute relatively minimal dollars.

British ColumbiaHydrocarbon Revenue by Product Type

SaskatchewanHydrocarbon Revenue by Product Type

Rest of Canada1

Hydrocarbon Revenue by Product Type


OilSands

ForecastFocus


NaturalGas



Crude Oiland LiquidsNatural

Gas

ForecastFocus



0

5

10

15

20

25

30

1990 1995 2000 2005 2010 2015

$C B

illio

ns

Taxes and Royalties

Current Income Taxes and Royalties PaidExploration and Production Companies Only2

Government royalties correlate closely with product revenue. Taxes also broadly track the industry’s revenue, but not completely; stubborn costs against a backdrop of falling prices reduce net income, hence the tax take.

The big cut in current (cash) taxes observed in 2009, and estimated for 2010, was a consequence of this “margin squeeze,” which was especially acute on the natural gas side of the business.

Like most other indicators, the high watermark for cash taxes and crown royalties was in 2008, when almost $25 billion was realized by the federal and provincial governments. Due to high levels of investment, total taxes (current plus future) reported by the industry are typically higher than the cash taxes expressed in the chart to the left. How-ever, future taxes vary considerably from year-to-year; in the Focus Period, they ranged between negative $3.5 billion to $3.5 billion (see also footnote 12).

Over the Forecast Period, the gov-ernments’ cash take should rise to $20 billion per year, but will depend on firm commodity prices that do not trigger income-reducing cost inflation.

Non-crown royalties are payments to landowners as opposed to government.

Crown royalties and taxes will rise to $20 billion per year by 2015, but will bedependent on commodity prices maintaining strength without triggering inflation.

Source: CAPP, Statistics Canada, ARC Financial Corp. Forecast PeriodFocus Period

Current TaxesCrown RoyaltiesNon-Crown Royalties


0

1

2

3

4

1990 1995 2000 2005 2010 2015

Roy

altie

s ($

C B

illio

ns)

0

2

4

6

8

10

12

14

16

1990 1995 2000 2005 2010 2015

Roy

altie

s ($

C B

illio

ns)

0

1

2

3

4

1990 1995 2000 2005 2010 2015

Roy

altie

s ($

C B

illio

ns)

0

1

2

3

4

1990 1995 2000 2005 2010 2015

Roy

altie

s ($

C B

illio

ns)

Royalties by Province

AlbertaRoyalties by Industry Segment

British ColumbiaRoyalties from Traditional Oil and Gas

SaskatchewanRoyalties from Traditional Oil and Gas

Rest of CanadaRoyalties from Traditional Oil and Gas


Oil SandsTraditional Oil and Gas

Following Alberta’s 2009 New Royalty Framework (NRF), the prov-ince’s royalties fell hard due to a drop in commodity prices and declining natural gas production. Alberta should realize a rebound in royalties during the Forecast Period, exceeding the $10 billion mark again by 2012. Better commodity prices on the futures curve are a principal driv-er, but so too is rising oil sands output. As well, competitive adjustments to the NRF are attracting much more growth capital for traditional oil and gas.

British Columbia experienced a royalty boom in the first half of the Focus Period, but quickly retreated due to depressed gas prices. Some recovery is expected, more so on the shoulders of rising natural gas production than price. Oil-focused Saskatchewan has experienced higher royalties on rising revenues.

Royalties from the east coast grew almost five-fold during the Focus Period. Offshore oil from Newfoundland was the primary source of the “Rest of Canada” category. An expected bump up in oil production from new, offshore satellite fields will contribute to higher Newfoundland royalties in 2011; how-ever, the gradual declining trend in out-put will temper future royalty income.





$1,000

$1,200

$1,400

$1,600

$1,800

$2,000

$2,200

2002 2003 2004 2005 2006 2007 2008 2009 2010

Wee

kly

Aver

age

Earn

ings

0

2

4

6

8

10

12

14

16

18

2 4 6 8 10 12 14 16 18 20 20+

Num

ber o

f Com

pani

es

Cost ($C per BOE)

0.00

0.50

1.00

1.50

2.00

2.50

3.00

1990 1995 2000 2005 2010 2015

Cos

t ($C

per

BO

E)

0.00

0.50

1.00

1.50

2.00

2.50

3.00

1990 1995 2000 2005 2010 2015

Cos

t ($C

per

BO

E)

Cost Indicators

General and Administrative CostsTotal Industry; per Unit of Production

Acute cost inflation was a dominant theme during the Focus Period. Some inputs such as steel demonstrated amplified cyclicality with the broader economy, but other factors like domestic labour did not. In fact, Weekly Average Earnings for Alberta’s oil and gas indus-try recovered quickly in the latter half of 2009, and are now at levels as high as recorded before the Financial Crisis.

Interest costs rose steeply on in-creased leverage, but are only expected to show a modest rise to 2015.

General and Administrative (G&A) costs are dominated by office salaries, leases and software licenses. G&A mod-erated at the end of the Focus Period, notwithstanding the spike in 2009 when one-time severance costs were recorded by some large companies. G&A costs are expected to be in the $2.25 to $2.50/BOE range, which is still high com-pared to a $1.00/BOE that was the rule-of-thumb 10 years ago.

Cost figures are averages. In fact, there is wide variability between compa-nies depending on factors like commod-ity choice, debt levels, geography and management discipline. For example, the upper right chart shows that vari-ability of operating costs across the industry is distributed like a bell curve.

2009 Operating Cost VariabilitySample Set of 60 Public Companies

Interest PaymentsTotal Industry; per Unit of Production

Source: Statistics Canada, CanOils, ARC Financial Corp.

ForecastFocus

ForecastFocus

Alberta Weekly Wage EarningsMining, Quarrying, Oil and Gas Extraction

Focus Period


0.00

10.00

20.00

30.00

40.00

50.00

1990 1995 2000 2005 2010 2015

Cos

t ($C

per

BO

E)

0.00

5.00

10.00

15.00

20.00

1990 1995 2000 2005 2010 2015

Cos

t ($C

per

BO

E)

Average Annual Operating Costs

Operating Cost per Unit of ProductionTraditional Oil and Gas Only

The Focus Period was highly inflationary for both oil sands and conven-tionally-produced oil and gas with operating cost escalation of over 50%.

Energy and labour are the dominant input factors for extracting hydro-carbons out of the ground and processing them for sale. Cash operating costs have historically shown a tight relationship with commodity prices in the up direction, but not necessarily down. Unit costs are usually ‘sticky’ during a commodity price retreat, such as in 2009, because wages in the field are not easily rolled back. For natural gas, fixed costs were spread over declining volumes, adding to the overall uptrend in unit costs.

Operating Cost per Unit of ProductionOil Sands Only

Source: CAPP, ARC Financial Corp. Source: CAPP, ARC Financial Corp.

ForecastFocus Period ForecastFocus Period

On the oil sands side of the business, the rise in production costs was tied to higher natural gas prices, a key input for most operations. Howev-er, labour, environmental compliance and logistics all became much more expensive during the front end of the Focus Period when capital expendi-tures and activity were rapidly escalating to record levels.

During the Forecast Period we expect further unit cost escalation of 5% per year, which is a fluid assumption that will depend on commod-ity prices, but intrinsically on the industry’s ability to offset cost increases with spending discipline and gains in productivity.

2%

Operating cost sensitivity to varyingrates of cost inflation

5%

10%

2%

5%

10%

Operating cost sensitivity to varyingrates of cost inflation


0

10

20

30

40

50

60

70

80

90

1990 1995 2000 2005 2010 2015

$C B

illio

ns

Total Industry Cash Flow and Capital Spending

Total After-Tax Cash Flow versus Capital ExpendituresCAPEX Stacked by Industry Segment

How much after-tax cash flow is invested back into the ground – as opposed to “leaking out” of the Cana-dian oil and gas economy – depends on numerous factors, including fiscal policy, but mostly on the profitability of the industry relative to other jurisdictions. Capital markets are highly efficient in rationing investment to domains where the greatest returns can be realized.

For much of the 1990s, the industry reinvested all of its cash flow, amplify-ing investment with additional debt and equity. Sentiment changed from 2000 onwards, when the industry began in-vesting less capital than it derived from domestically generated cash flow. Pro-liferation of the energy trust structure, which distributed much of its cash flow to unitholders, was part contributor to this phenomenon. Constrained oppor-tunity and diminishing profitability in Canadian natural gas also factored into cash flow leakage.

Cash flow is expected to rise in the Forecast Period in conjunction with greater revenue, but the trend will be captive to cost pressures. Capital spending should rise and then level out around $55 billion per year, with the primary restraints being inflationary tension and opportunity constraint.

Over the next five years, the industry is expected to reinvestalmost all of its $55 billion per year of cash flow.



Total After-Tax Cash FlowOil Sands CAPEXTraditional Oil and Gas CAPEX


0

5

10

15

20

25

30

1990 1995 2000 2005 2010 2015

$C B

illio

ns

0

10

20

30

40

50

60

70

1990 1995 2000 2005 2010 2015

$C B

illio

ns

Cash Flow and Capital Spending by Segment

Source: CAPP, ARC Financial Corp. Source: CAPP, ARC Financial Corp. ForecastFocus Period ForecastFocus Period

CashFlowCapital

Expenditures

Traditional cash flow peaked at over $65 billion before falling by two-thirds during the Financial Crisis. Recovery can be seen, however, cost pressures and much lower gas prices preclude a return to the 2008 peak.

Elimination of the trust structure, expansion of the opportunity set into resource plays and expectation of attractive returns suggest that the traditional side of the business will invest 100% of its cash flow during the Forecast Period. However, more attractive economics for oil plays imply that the spending bias will be skewed toward conventional liquids and crude oil. Investment into dry natural gas will be restrained except into select resource plays where costs are continentally competitive.

Oil sands cash flow fell hard in 2008 too, but unlike the traditional side of the business, recovery has been swift and is trending higher early in the Forecast Period. Production growth and strong oil prices are the primary drivers. Cost inflation is potentially most acute in the oil sands segment, with widely variable sensitivities shown in the chart.

Capital spending in the Forecast Period (a total of $104 billion) has been estimated by aggregating announced projects by companies active in the region. Many variables, including oil prices, regulatory pressures, labour costs and logistical constraints will determine total spending.

After-Tax Cash Flow and Capital SpendingTraditional Oil and Gas Only

After-Tax Cash Flow and Capital SpendingOil Sands Only

CapitalExpenditures

CashFlow 2%

Sensitivity of cash flow to rate

of cost inflation

5%

10%

2%

5%

10%

Sensitivity of cash flow to rate

of cost inflation


-5

0

5

10

15

20

25

30

1990 1995 2000 2005 2010

$C B

illio

ns

Capital Markets

Equity and Debt Capital RaisedAnnual Financings Including Trusts

Debt and equity financings add substantial momentum to the flow of capital. Despite the Financial Crisis, financings in the Canadian oil and gas industry were remarkably healthy throughout the Focus Period. In fact, the fourth greatest infusion of debt and equity since 1990 was in 2009, during the Great Recession. However, the numbers alone are deceiv-ing, because the availability of capital became much more selective. By 2010, investment dollars were polarized, targeting mostly companies with economies of scale, an oil bias, a high-quality management team, or all of the above. Annual infusion of between $15 billion and $20 billion of debt and equity appears to be the new norm.

Inflow of foreign capital into the Canadian oil and gas economy was one of the biggest megatrends to begin in the latter half of the Focus Period. Since August 2009, $18.5 billion of funding has been pumped into the system, mostly in the form of joint venture financings. In 2010, this new source of “unconventional” capital largely favoured large oil sands projects. However, natural gas resource plays also began attracting dollars in early 2011. More foreign capital is expected in the Forecast Period, but how much will depend on many factors, including the balance between cash flow and financing needs. Stable government policies and opening exports to Pacific markets will also dictate availability of new capital.

Source: Sayer Energy Advisors, ARC Financial Corp. Source: Company Press Releases, ARC Financial Corp.

Focus Period

Equity

Debt

Date Deal Type ($Bln) Target

2009-Aug Athabasca / PetroChina Joint Venture 1.90 Oil Sands

2010-Apr Syncrude / Sinopec Joint Venture 4.65 Oil Sands

2010-May PennWest / China SWF Joint Venture 1.25 Oil Sands

2010-Aug PennWest / Mitsubishi Joint Venture 0.85 Natural Gas

2010-Aug Laricina / Korea Invest Corp Equity 0.05 Oil Sands

2010-Nov Statoil / Thailand PTT E&P Equity 2.30 Oil Sands

2010-Nov OSUM / Korea Invest Corp. Equity 0.10 Oil Sands

2010-Dec Talisman / Sasol Joint Venture 1.00 Natural Gas

2011-Feb EnCana / CNPC Joint Venture 5.40 Natural Gas

2011-Mar Talisman / Sasol Joint Venture 1.00 Natural Gas

Total 18.50

Canadian Oil and Gas FinancingsFrom Foreign Capital Sources


0

2

4

6

8

10

12

14

1990 1995 2000 2005 2010

Cos

t of C

apita

l (%

)

0

2

4

6

8

10

12

14

16

1990 1995 2000 2005 2010 2015

$C B

illio

ns

Dividends, Distributions and BuybacksCapital Outflow Excluding Foreign Investment

Weighted Average Cost of Capital (WACC)Estimated WACC for Upstream Producers3

Source: ARC Financial Corp. Focus Period


Cash flow that is not reinvested back into the system is either deployed elsewhere (“leakage”), taken out of circulation to pay corporate dividends and distributions, or used to repay debt and buy back equity. Prolifera-tion of income trusts drove significant growth in unitholder distributions between 2000 and 2009. During the Focus Period, good profitability and constrained opportunity led to a significant increase in distributions, share buybacks and debt repayment.

Dividend policies have been in flux since royalty trusts started convert-ing into corporations. Less outflow is expected, because investing growth capital appears more advantageous to shareholders than giving it back.

The industry’s weighted average cost of capital (WACC) led a broad, 15-year decline to 2005. Both debt and equity became cheaper reflecting falling interest rates and a rising market for equities.

The front end of the Focus Period saw a rise in WACC followed by a de-cline that continued into the financial crisis. Estimating WACC3 during this turbulent and extraordinary time is imprecise and potentially mis-leading. In fact, the cost of capital was highly polarized during late 2008 and early 2009 when the Financial Crisis hit. Smaller companies had almost no access to capital at any price; while larger companies enjoyed ongoing ability to tap markets.

Source: CanOils, ARC Financial Corp.

Capital Markets


0.0

0.5

1.0

1.5

2.0

2.5

3.0

2000 2002 2004 2006 2008 2010

Tota

l Bon

us ($

C B

illio

ns)

0.0

0.2

0.4

0.6

0.8

1.0

1.2

2000 2002 2004 2006 2008 2010

Tota

l Bon

us ($

C B

illio

ns)

0.0

0.5

1.0

1.5

2.0

2.5

3.0

2000 2002 2004 2006 2008 2010

Tota

l Bon

us ($

C B

illio

ns)

0.0

0.5

1.0

1.5

2.0

2000 2002 2004 2006 2008 2010

Tota

l Bon

us ($

C B

illio

ns)

Land Bonuses

British ColumbiaTraditional Oil and Gas Land Sales

SaskatchewanTraditional Oil and Gas Land Sales

AlbertaOil Sands Region Land Sales

Source: Government Websites, ARC Financial Corp.

The amount spent on land (bonuses) in any one year is a small fraction of total capital expenditures. However, the year-over-year pattern of spending is an important leading indicator of activity and competitive health.

Capital migrated away from Alberta between 2007 and 2009 due to the neg-ative effects of the New Royalty Frame-work on profitability. More attractive fiscal regimes in B.C. and Saskatchewan attracted Alberta’s investment dollars, especially in 2008. Both provinces had the added attraction of previously iden-tified resource plays conducive to new drilling and completion technologies.

Capital began migrating back to Alberta in 2010 as a result of the revamped NRF, which made prospect-ing for traditional oil in the oil-rich province economic again. Land bonuses in B.C. have receded due to low natural gas prices and diminished availability of land in high quality play areas.

Land sales in the geographically limited oil sands region peaked in 2006 and have shown little activity since. Economically viable areas are now fully staked and the sector is mostly in the project development mode.

AlbertaTraditional Oil and Gas Land Sales

Focus Period Focus Period

Focus PeriodFocus Period


0%

10%

20%

30%

40%

50%

1960 1970 1980 1990 2000 2010

Hor

izon

tal W

ells

/ To

tal W

ells

0

5,000

10,000

15,000

20,000

25,000

30,000

1990 1995 2000 2005 2010 2015

Num

ber o

f Wel

ls

Western Canadian Sedimentary Basin Well Trends

Annual Well Count by SegmentWells Drilled per Year4

After rising steadily for 15 years, the number of wells drilled in the WCSB fell precipitously during the Focus Period. Alberta’s New Royalty Framework, low natural gas prices and a financial crisis were culpable trend busters. However, redirection of capital away from high frequency shallow gas wells in favour of fewer, more productive horizontal ones (see adjacent chart) was also a major factor in reducing the well count.

Going forward, the annual well count should range between 12,000 and 15,000, but the next few pages will show that the character of the underlying wells will be very different than those drilled prior to 2006.

Market Share of Horizontal WellsPercentage of Total Wells Drilled Horizontally

Drilling wells horizontally into rock formations to enhance productiv-ity is nothing new. The technique was adopted in meaningful numbers back in the early 1990s when its implementation grew to 10% of all wells drilled. High cost and niche applicability kept its share of the drilling market steady until 2006, when the technique began to be applied to tight oil formations in Saskatchewan and subsequently in the Montney and Horn River gas formations in northeastern B.C. The uptrend in the percentage share of horizontal wells is due to an increase in their number, but also is a consequence of far fewer shallow, vertical gas wells.

Source: JuneWarren-Nickle’s Energy Group, ARC Financial Corp. Source: geoSCOUT, ARC Financial Corp.

ForecastFocus PeriodFocus

Oil SandsTraditional


0

2,000

4,000

6,000

8,000

10,000

12,000

1960 1970 1980 1990 2000 2010

Wel

ls D

rille

d pe

r Yea

r

0

1,000

2,000

3,000

4,000

5,000

6,000

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Num

ber o

f Hor

izon

tal W

ells


Total Number of Horizontal WellsAnnual Count By Province Over Time4

Source: geoSCOUT, ARC Financial Corp.

Shallow Natural Gas Drilling ActivityNumber of Wells Drilled in Southeastern Alberta


The absolute number of horizontal wells in the WCSB began trend-ing upward at the start of the Focus Period in 2005. Notwithstanding the 2009 dip, the trend has been growing upward at a rate of about 400 per year with significant momentum building into 2010.

Although the tight natural gas formations in B.C. have attracted big headlines, much of the growth in horizontal drilling has come from the oil formations in Saskatchewan and Manitoba. In 2010, large growth was recorded in Alberta as the industry began mobilizing the technology to revisit drilling for oil in historic plays like the Viking and the Cardium.

The major shift toward more prolific horizontal wells has come at the expense of traditional shallow vertical wells. One of the most dramatic changes in the Canadian oil and gas industry over the past five years has been the precipitous 80% drop in the number of wells drilled in the shal-low gas region surrounding Medicine Hat, Alberta.

Many factors have led to the rise and demise of drilling shallow wells in southeastern Alberta, but above all it has been the highly productive inno-vations in drilling and completing horizontal wells that have changed the complexion of how and where companies seek new natural gas supplies.

Focus

Manitoba British Columbia Saskatchewan Alberta

Focus Period


0

100

200

300

400

500

0 1,000 2,000 3,000 4,000 5,000 6,000

Num

ber o

f Hor

izon

tal W

ells

Measured Depth (Metres)

0

100

200

300

400

500

0 1,000 2,000 3,000 4,000 5,000 6,000

Num

ber o

f Hor

izon

tal W

ells

Measured Depth (Metres)


Horizontal Well Depth Profile 2005Histogram of Well Depths Segmented By Province


Horizontal Well Depth Profile 2010Histogram of Well Depths Segmented by Province

Not only is the industry drilling more horizontal wells every year, but on average the wells are being drilled progressively deeper and longer. Five years ago the average total measured depth of a horizontally drilled well was 2,000 meters; now it is over 500 meters longer at 2,500 meters, and the trend to more laterals and greater length appears to be continuing.

The histograms above display the number of horizontally drilled wells at each depth range, in 250 meter increments. For example, in 2005 (left chart) there were a total of 450 horizontal wells drilled between the total measured depths of 2,000 and 2,250 meters. That was the most commonly

drilled depth in 2005 and pretty close to the average of all the wells in that distribution. Also, note in 2005 that there were very few horizontal wells drilled to depths greater than 3,000 meters.

By 2010, the well depth profile had shifted dramatically to the right. Over 30% of the wells were over 3,000 meters and the overall average in-creased to 2,500 meters and with greater variability than in 2005. Deeper depths were recorded in all provinces, but mostly in B.C. where by 2010 nearly all wells were drilled to greater than 3,000 meters. A big implica-tion of this trend is that well costs, and productivity, are rising.





0.0

0.5

1.0

1.5

2.0

2.5

1990 1995 2000 2005 2010 2015

Cos

t per

Wel

l ($C

Mill

ions

)

0.0

0.5

1.0

1.5

2.0

2.5

1990 1995 2000 2005 2010 2015

Cos

t per

Wel

l ($C

Mill

ions

)

0

1

2

3

4

5

6

7

1990 1995 2000 2005 2010 2015

Cos

t per

Wel

l ($C

Mill

ons)

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1990 1995 2000 2005 2010 2015

Cos

t per

Wel

l ($C

Mill

ions

)

Average Drilling and Completion Cost per Well, by Province

Source: CAPP, JuneWarren-Nickle’s Energy Group, ARC Financial Corp.

At first glance, the aggressively ris-ing well cost trends on this page are disconcerting. However, they are a direct consequence of the two trends highlighted on previous pages: a shift to more horizontal wells and a propensity to drill deeper and longer distances. Average well costs in Northeastern B.C. have risen the fastest, because that’s where the industry has concentrated its deepest horizontal drilling efforts. Chal-lenging topography and seasonality adds complexity, which is why B.C.’s average well cost is pushing $5 million.

Development of Saskatchewan’s tight oil resource plays are requiring more capital too. Unlike in B.C., wells in southern Saskatchewan are much shallower and the topography easier to manage. Alberta’s costs have risen in similar vein to B.C. and Saskatchewan, but migration to resource plays in Al-berta has lagged. We expect the average well cost in Alberta to keep rising as the industry migrates to exploiting more resource plays and less shallow gas.

Although well costs have risen significantly, so too has productivity. Finding and development costs measure the balance between the two (p. 46).



AlbertaAverage Cost of All Wells; Excludes Oil Sands

British ColumbiaAverage Cost of All Wells

SaskatchewanAverage Cost of All Wells

Total IndustryAverage Cost of All Wells; Excludes Oil Sands


0

500

1,000

1,500

2,000

2,500

3,000

1990 1995 2000 2005 2010

Volu

me

(MM

BO

E p

er Y

ear)

Canadian Oil and Gas Reserve AdditionsEstablished Additions; Excluding Oil Sands

Reserve Additions

Focus Period

Capital spending on drilling and infrastructure adds to the reserves of the industry, which is a volume measure of inventory in the ground. However, because the subsurface is not visible and geology is complex, the measurement of reserves is not an exact science, and is estimated in terms of the probability of what is likely recoverable at market prices.

Annual reserve additions estimated by CAPP represent established reserves.

Notionally, reserve additions should vary with capital spending, but changes in expected commodity prices, produc-tion output, exploration successes (or failures) and productivity gains (or losses) all affect how much volume and value the industry creates in the ground.

Reserve additions mark the final point on our capital flow diagram, before a new cycle begins. How much upstream capital that is expended, and what financial returns are generated to find a new barrel of reserve through the round-the-wheel process of value creation, are key metrics that reflect the health of the industry’s fiscal pulse. The measurement of reserves is not an exact science, and is estimated in terms

of the probability of what is likely recoverable at market prices.




Section 4

Economic Viability


Long-Term Average Finding and Development Costs

Industry Average Finding and Development Costs5 Five-Year Moving Average Per Unit of Established Reserves

Finding and development (F&D) costs measure how much capital it takes to book an incremental BOE of produc-ible hydrocarbons on the balance sheet.

F&D costs are open to considerable debate due to varying interpretations of what constitutes a realistically produc-ible reserve. Numbers represented here are based on established reserves as provided from the CAPP dataset.

Our five-year averaged chart is best interpreted as a directional indicator rather than a resource for absolute num-bers. “Basin maturity” – progressively harder-to-find and smaller accumula-tions of hydrocarbons – has been a major force driving F&D costs higher between the mid-1990s and mid-2000s.

The concerning rise in F&D costs moderated in the late 2000s. A fall in drilling and service costs was part of the reason. Proportionately larger reserve additions from resource plays, for ex-ample natural gas in B.C., were another.

The unsustainable trend of ris-ing F&D costs has potentially been arrested. Up to the Focus Period the WCSB was hostage to technology and profitability limitations. Migration to fresh resource plays with new, produc-tivity enhancing technologies signals competitive renewal for the WCSB.

The unsustainable trend of rising F&D costs has potentially been arrested by the migration to ‘immature’ resource plays with new technology.


0.00

5.00

10.00

15.00

20.00

25.00

1970 1975 1980 1985 1990 1995 2000 2005

Cos

t ($C

per

BO

E)

Focus


$0.00

$5.00

$10.00

$15.00

$20.00

$25.00

2002 2003 2004 2005 2006 2007 2008 2009

Cos

t ($C

per

BO

E)

Near-Term Average Finding and Development Costs

Average Finding, Development and Acquisition Costs5 By Company Size; Per Unit of Proven plus Probable Reservesa

Unlike the F&D chart on the previ-ous page, this one is more indicative of recent, absolute costs under the NI-51-101 accounting standard.

Unsmoothed and taken from the financial statements of publicly-traded companies, the data here represents F&D costs for proven plus probable reserves, which explains why the num-bers are lower than the prior chart. Peak F&D costs were recorded in 2006, with a gradual decline to 2009, for reasons mentioned in the previous page.

Differentiating by company size shows that F&D costs have historically been consistent regardless of size. How-ever, the consistency disconnected in 2009, mostly due to economies of scale and productivity gains being realized by the larger companies leading the trend toward resource plays.

F&D costs are difficult to predict. Productivity gains in resource plays are being realized by most companies, therefore the F&D gap between large and small should reconverge, although access to large quantums of capital may be challenging for smaller enterprises. The ability of the industry as a whole to offset higher well costs with productiv-ity gains will be key to reducing future F&D costs.

The ability of the overall industry to offset inflationary forces with productivityenhancing technologies will be key to improving future F&D costs.


Mid Caps6

Small Caps

Focus Perioda With future development capital


-5%

0%

5%

10%

15%

20%

1990 1995 2000 2005 2010 2015

RO

CE

(%)

Upstream Industry Return on Capital Employed

Annual Return on Capital Employed7

Estimated Average of All Oil and Gas ProducersFinding, developing and bringing

crude oil and natural gas to market is a very capital intense business. Return on capital employed, or ROCE, is a measure of how effectively the industry is deploying its total capital. Higher returns, especially in excess of the cost of capital, give greater incentive for companies to keep investing.

Between 2000 and 2005, industry ROCE was rising in tandem with com-modity prices, at a time when cost infla-tion was not yet a drag on net income.

Rising costs combined with larger capital commitments put ROCE on a declining trend during the Focus Period.

Note that $85 billion of capital de-ployed into oil sands projects during the Focus Period has a long lead time before generating returns. This surge in invest-ment without immediate return is a factor that is blended into the industry’s ROCE during the Focus Period and has contributed to its downward bias.

ROCE shows a mild decline over the Forecast Period. That’s the effect of esca-lating costs under relatively flat oil and gas prices in the Base Case. Dashed lines bound a band of cost inflation scenarios.

Higher returns on capital give greater incentiveto reinvest back into the business.



2%

Sensitivity of ROCE to varying ratesof cost inflation

5%

10%


-15%

-10%

-5%

0%

5%

10%

15%

20%

25%

30%

1990 1995 2000 2005 2010 2015

RO

E (%

)

Upstream Industry Shareholders’ Returns

Annual Return on Equity8

Estimated Average of All Oil and Gas ProducersReturn on equity (ROE) measures

the profitability of the industry from the perspective of shareholders’ capital.

As with returns on capital employed on the previous page, historical returns on equity are highly sensitive to oil and gas price variability.

After depressed and choppy returns in the 1990s, ROE rebounded to unusually high levels in the first half of the 2000s. Such robust levels are not expected to repeat soon, notwithstand-ing another bout of commodity price appreciation that outstrips inflation.

ROE is expected to be in the more historically normal 7% to 11% range under Base Case forward prices. High and low cost inflation scenarios are charted. Note these return expectations represent averages for the entire indus-try. Realistically, there will be wide vari-ablility between poor performing and exceptional companies (see for example Operating Cost Variability, p. 32).

Although declining ROE is indicated in the Forecast Period, the volatile inter-play between commodity price flucta-tions and costs will ensure that realized ROE year-over-year will not be smooth.

Unusually high returns on equity will only repeat if rapid commodity priceappreciation outstrips cost inflation, as it did between 2000 and 2005.


Forecast Focus Period

2%

Sensitivity of ROE to varying ratesof cost inflation

5%

10%


-20%

-15%

-10%

-5%

0%

5%

10%

15%

1990 1995 2000 2005 2010

Valu

e C

reat

ion

(%)

Industry Value Creation

Returns in Excess of the Weighted Average Cost of Capital9

All Oil and Gas ProducersIs value being created by the Canadian oil and gas industry? One measure of value creation is if the industry’s return on capital exceeds its weighted average cost of capital (see WACC page 37). On an annual basis, this chart shows the difference between the two metrics.The industry’s viability was tenuous for most of the 1990s when returns on capital were low and WACC high. A re-turn to positive value creation ensued in 2000 when commodity prices recovered amidst less expensive capital.Declining WACC and rising commod-ity prices led to a period of unusually strong value creation between 2000 and 2005. Gains were eroded during the Focus Period after ROCE fell hostage to cost inflation. Not surprisingly, the Financial Crisis cut into value creation in 2009 too. Weak performance on the natural gas side of the business has precluded recovery in 2010.The outlook for value creation is mildly positive over the Forecast Period. WACC is unlikely to go much lower and returns on capital will depend mostly on com-modity prices, cost containment and productivity gains.


Focus Period

A rapidly declining cost of capital amidst fast rising commodity prices led to a period of unusually strong value creation in the first half of last decade.


Section 5

Sensitivity Analysis and Tables


The Fiscal Pulse with Varying Oil and Gas Prices

A Sensitive IndustryFive years from now, hindsight will assuredly

prove that the stiff, market-derived Base Case price forecasts were wrong. If nothing else, price volatility – such as we are experiencing from violent events in North Africa and the Middle East at time of writing – will induce theatrical ups and downs in key metrics like revenue and cash flow.

To be sure, commodity prices are the most influential factor in determining the fiscal pulse of the business. To see the effect of oil and gas price volatility on key capital flow and profit-ability metrics, we have constructed sensitivity tables on the following three pages.

We took the mid-point of the Forecast Period, 2012, as the representative year to pivot prices around. In Table 1, each offsetting box from the centre adds or subtracts $US 30.00/B off the Base Case oil price, and subtracts $1.00/Mcf or adds $2.00/Mcf off natural gas. In this way you can see the effect of price variations in either one or both commodities.

Expected values are recorded for revenue, cash flow, return on capital employed (ROCE) and well count. Totals for the entire industry have been calculated, and where possible each of those metrics have been broken down into the traditional and oil sands segments of the business.

Table 2 illustrates the same concept, except the values recorded in each box represent dif-ferences from the 2012 Base Case (we do the subtractions in Table 1 for you). Table 3 is the same as Table 2, except deviations are reported on a percentage basis.

Extremes offer the best insights into, “what if ?” The most bullish box is at the bottom right with oil at $122/B and natural gas at $6.25/Mcf. Revenue rises to $164.1 billion, cash flow jumps to $84.3 billion and average returns top 13.8%. We have discussed that the primary challenges of such full-bodied metrics are labour shortages and cost inflation with no proportional im-provements in productivity.

Diagonally up to the top left corner of the matrix is the bearish price combination of $62.00/B oil and $3.25/Mcf natural gas. Re-turns effectively fall to zero as revenue is cut by a third from the Base Case. Costs are unlikely to fall as fast as price, which will crimp investment in the absence of subsequent price recovery, productivity gains, or both.

Recall that commodity price strength and production volumes are now heavily skewed toward oil. Therefore, at an industry level, our matrix shows that what happens to oil prices is more impactful than what happens to natural gas. Importantly, below an oil price of $US 60.00/B the industry is broadly unprofitable and doesn’t generate sufficient returns to entice

reinvestment of cash flow. This last point stresses the need for vigorous innovation to boost the industry’s productivity as an antidote to the potential trauma of falling oil prices.

Ongoing Health Through Turmoil and Renewal

In today’s context, the centre Base Case box represents metrics afforded to a fairly healthy “patient,” as described in our Industry Check-Up. Under those circumstances the industry finds a balance of capital flows that delivers, “rewarding levels of prosperity to all stakeholders, within the bounds of world-class regulatory standards.”

Yet even if oil and gas prices were reasonably constant at Base Case levels, we know that fiscal stability in the industry will always be fleeting. Other forces, like competition, substitution and technological change, will relentlessly pose risks and challenges - and of course opportunities too.

Within Canada’s largest industry, fiscal health will be reserved for stakeholders who remain flexible, innovative and proactive amidst volatile and changing circumstances. This is nothing new; turmoil and renewal has been a theme in this industry for over 150 years.

Fiscal stability in the Canadian oil and gas business will always be fleeting.


Traditional Oil Sands

Oil Sands TotalTraditional TotalOil Sands

na na 12,800

$79.7 $50.2 $129.9$63.1 $32.7 $95.8

$8.7 $32.7

$53.2 $32.7

$49.9 $34.4

Table 1: Absolute Sensitivity to Oil and Gas Price Changes10

Oil Price Sensitivity (WTI)N

atur

al G

as P

rice

Sens

itivi

ty (A

ECO

)

Revenue(Billions)

Cash Flow(Billions)

Wells(No. per year)

ROCE(% per year)

Traditional Oil Sands Total

$48.2

$20.1

na

na

$32.7

$8.9

na

na

$80.9

$29.0

0.8%

8,100

Traditional Oil Sands Total

$64.8

$31.3

na

na

$50.2

$23.1

na

na

$115.0

$54.4

7.2%

11,600

Traditional Total

$81.4

$40.7

na

na

$67.8

$35.7

na

na

$149.2

$76.4

12.2%

14,600

$24.0

na

na

na

na

$85.9

1.7%

9,350

Traditional

$69.8

$34.7

na

$50.2

$22.8

na

$120.0

$57.5

7.9%

Traditional Total

$86.4

$43.9

na

na

$67.8

$35.4

na

na

$154.2

$79.3

12.8%

15,700

Total

$31.1

na

na

$7.8

na

na

$38.9

3.3%

11,550

Traditional Total

$40.7

na

na

$21.7

na

na

$62.4

9.0%

14,600

Traditional Total

$96.3

na

na

$67.8

na

na

$164.1

$84.3

13.8%

17,500

Oil Sands

Oil Sands

Oil Sands Oil Sands

Base Case less $30.00/B(at $62.30 / B)

Base Case Price in 2012(at $92.30 / B)

Base Case plus $30.00/B(at $122.30 / B)

Bas

e C

ase

2012

(at $

C 4

.25

/ Mcf

)B

ase

Cas

e le

ss $

1(a

t $C

3.2

5 / M

cf)

Bas

e C

ase

plus

$2

(at $

C 6

.25

/ Mcf

)

Revenue(Billions)

Cash Flow(Billions)

Wells(No. per year)

ROCE(% per year)

Revenue(Billions)

Cash Flow(Billions)

Wells(No. per year)

ROCE(% per year)

Revenue(Billions)

Cash Flow(Billions)

Wells(No. per year)

ROCE(% per year)

Revenue(Billions)

Cash Flow(Billions)

Wells(No. per year)

ROCE(% per year)

Revenue(Billions)

Cash Flow(Billions)

Wells(No. per year)

ROCE(% per year)

Revenue(Billions)

Cash Flow(Billions)

Wells(No. per year)

ROCE(% per year)

Revenue(Billions)

Cash Flow(Billions)

Wells(No. per year)

ROCE(% per year)

Revenue(Billions)

Cash Flow(Billions)

Wells(No. per year)

ROCE(% per year)


TotalTraditionalTotalOil SandsTraditional

Traditional TotalOil Sands Traditional Oil Sands Total

Oil SandsTraditionalOil SandsTraditionalTotalTraditional

Table 2: Relative Differences to the 2012 Base Case in $


atur

al G

as P

rice

Sens

itivi

ty (A

ECO

)

- $21.6

- $14.6

na

na

- $17.5

- $13.9

na

na

- $39.1

- $28.5

- 7.1

- 4,700

- $5.0

- $3.4

na

na

$0.0

+ $0.3

na

na

- $5.0

- $3.1

- 0.7

- 1,200

+ $11.6

+ $6.0

na

na

+ $17.6

+ $12.9

na

na

+ $29.2

+ $18.9

+ 4.3

+ 1,800

- $16.6

- $10.7

na

na

- $17.5

- $14.1

na

na

- $34.1

- $24.8

- 6.2

- 3,450

$0.0

$0.0

na

na

$0.0

$0.0

na

na

$0.0

$0.0

0.0

0

+ $16.6

+ $9.2

na

na

+ $17.6

+ $12.6

na

na

+ $34.2

+ $21.8

+ 4.9

+ 2,900

- $6.7

- $3.6

na

na

- $17.5

- $15.0

na

na

- $24.2

- $18.6

- 4.6

- 1,250

+ $9.9

+ $6.0

na

na

$0.0

- $1.1

na

na

+ $9.9

+ $4.9

+ 1.1

+ 1,800

+ $26.5

+ $15.2

na

na

+ $17.6

+ $11.6

na

na

+ $44.1

+ $26.8

+ 5.9

+ 4,700

Bas

e C

ase

2012

(at $

C 4

.25

/ Mcf

)B

ase

Cas

e le

ss $

1(a

t $C

3.2

5 / M

cf)

Bas

e C

ase

plus

$2

(at $

C 6

.25

/ Mcf

)Base Case less $30.00/B

(at $62.30 / B)Base Case Price in 2012

(at $92.30 / B)Base Case plus $30.00/B

(at $122.30 / B)

Revenue(Billions)

Cash Flow(Billions)

Wells(No. per year)

ROCE(% per year)

Revenue(Billions)

Cash Flow(Billions)

Wells(No. per year)

ROCE(% per year)

Revenue(Billions)

Cash Flow(Billions)

Wells(No. per year)

ROCE(% per year)

Revenue(Billions)

Cash Flow(Billions)

Wells(No. per year)

ROCE(% per year)

Revenue(Billions)

Cash Flow(Billions)

Wells(No. per year)

ROCE(% per year)

Revenue(Billions)

Cash Flow(Billions)

Wells(No. per year)

ROCE(% per year)

Revenue(Billions)

Cash Flow(Billions)

Wells(No. per year)

ROCE(% per year)

Revenue(Billions)

Cash Flow(Billions)

Wells(No. per year)

ROCE(% per year)

Revenue(Billions)

Cash Flow(Billions)

Wells(No. per year)

ROCE(% per year)

Oil Sands Total Total

Traditional Total

Traditional Total

Oil Sands

Oil Sands Oil Sands


Traditional TotalOil Sands Traditional TotalOil Sands Traditional Oil Sands Total

Traditional TotalOil Sands Traditional TotalOil Sands

TotalOil SandsTraditionalOil Sands TotalTraditionalOil SandsTraditional

- 31%

- 42%

na

na

- 35%

- 61%

na

na

- 33%

- 50%

- 90%

- 37%

- 7%

- 10%

na

na

+ 0%

+ 1%

na

na

- 4%

- 5%

- 9%

- 9%

+ 17%

+ 17%

na

na

+ 35%

+ 57%

na

na

+ 24%

+ 33%

+ 54%

+ 14%

- 24%

- 31%

na

na

- 35%

- 62%

na

na

- 28%

- 43%

- 78%

- 27%

0%

0%

na

na

0%

0%

na

na

0%

0%

0%

0%

+ 24%

+ 27%

na

na

+ 35%

+ 55%

na

na

+ 29%

+ 38%

+ 62%

+ 23%

- 10%

- 10%

na

na

- 35%

- 66%

na

na

- 20%

- 32%

- 58%

- 10%

+ 14%

+ 17%

na

na

+ 0%

- 5%

na

na

+ 8%

+ 9%

+ 14%

+ 14%

+ 38%

+ 44%

na

na

+ 35%

+ 51%

na

na

+ 37%

+ 47%

+ 75%

+ 37%

Revenue(Billions)

Cash Flow(Billions)

Wells(No. per year)

ROCE(% per year)

Revenue(Billions)

Cash Flow(Billions)

Wells(No. per year)

ROCE(% per year)

Revenue(Billions)

Cash Flow(Billions)

Wells(No. per year)

ROCE(% per year)

Revenue(Billions)

Cash Flow(Billions)

Wells(No. per year)

ROCE(% per year)

Revenue(Billions)

Cash Flow(Billions)

Wells(No. per year)

ROCE(% per year)

Revenue(Billions)

Cash Flow(Billions)

Wells(No. per year)

ROCE(% per year)

Revenue(Billions)

Cash Flow(Billions)

Wells(No. per year)

ROCE(% per year)

Revenue(Billions)

Cash Flow(Billions)

Wells(No. per year)

ROCE(% per year)

Revenue(Billions)

Cash Flow(Billions)

Wells(No. per year)

ROCE(% per year)

Total

Traditional TotalOil Sands

Table 3: Relative Percent Differences to the 2012 Base Case


atur

al G

as P

rice

Sens

itivi

ty (A

ECO

)

Bas

e C

ase

2012

(at $

C 4

.25

/ Mcf

)B

ase

Cas

e le

ss $

1(a

t $C

3.2

5 / M

cf)

Bas

e C

ase

plus

$2

(at $

C 6

.25

/ Mcf

)Base Case less $30.00/B

(at $62.30 / B)Base Case Price in 2012

(at $92.30 / B)Base Case plus $30.00/B

(at $122.30 / B)


Table 4: Aggregate Data For All Regions (Base Case)

2005 2006 2007 2008 2009 2010E 2011E 2012E 2013E 2014E 2015EProduction/Sales Traditional Oil & Liquids MBOE/d 2,009 2,003 2,033 1,957 1,837 1,788 1,769 1,716 1,684 1,653 1,652 Oil Sands MBOE/d 992 1,126 1,199 1,207 1,331 1,482 1,612 1,763 1,917 2,049 2,176 Natural Gas MMCf/d 17,071 17,100 16,860 16,201 15,084 14,552 14,018 13,591 13,347 13,243 13,323 TOTAL MBOE/d 5,846 5,979 6,042 5,864 5,683 5,696 5,718 5,744 5,825 5,910 6,049 Prices WTI $US/B 56.56 66.07 72.32 99.53 61.70 79.50 92.25 92.30 91.40 91.00 91.30 Exchange Rate $US/$C 0.83 0.88 0.94 0.94 0.88 0.97 1.00 0.98 0.98 0.98 0.98 Edmonton Light $/B 68.72 72.89 76.97 102.66 66.25 77.55 92.35 93.40 93.00 92.70 92.65 Bitumen Wellhead $/B 27.96 40.55 40.99 71.04 52.60 59.12 65.30 64.31 62.26 60.30 58.52 Synthetic $/B 70.91 72.56 79.29 106.91 69.47 80.53 94.93 96.03 95.61 95.29 95.24 Natural Gas $/Mcf 8.58 6.32 6.25 7.95 4.05 3.80 3.75 4.25 4.50 4.65 4.80 Average Price per Unit $/BOE 51.32 47.35 49.57 67.95 42.93 48.14 55.12 57.25 57.83 57.92 58.01 Revenues Traditional Oil & Liquids $MM 39,916 41,317 45,309 60,313 37,350 42,759 49,753 48,702 47,409 46,216 45,997 Oil Sands $MM 16,127 22,561 25,553 38,102 29,392 37,143 46,103 50,253 53,589 56,232 58,740 Natural Gas $MM 53,460 39,445 38,462 47,011 22,298 20,184 19,177 21,083 21,939 22,483 23,329 TOTAL REVENUES $MM 109,504 103,323 109,324 145,425 89,040 100,086 115,033 120,039 122,937 124,931 128,066 Royalties Total Net Royalties $MM 16,641 15,162 15,105 21,070 10,101 12,507 15,078 16,075 16,438 16,592 16,993 Royalties per Unit $/BOE 7.80 6.95 6.85 9.84 4.87 6.02 7.22 7.67 7.73 7.69 7.70 Total Crown Royalties $MM 14,409 13,265 13,596 18,833 8,767 11,219 13,552 14,454 14,778 14,910 15,274 Taxes Reconciliation of Estimated Permanent Differences11 $MM 4,065 4,742 4,362 6,151 3,091 - 1,500 1,500 1,500 1,500 1,500 Federal Income Tax (incl LCT) $MM 4,308 4,238 4,432 3,608 2,049 2,762 2,736 2,538 2,454 2,455 2,439 Provincial Income Tax $MM 1,911 2,042 2,134 2,095 1,644 1,534 1,481 1,642 1,611 1,612 1,551 Total Current Taxes $MM 6,219 6,280 6,566 5,703 3,693 4,296 4,217 4,180 4,065 4,067 3,990 Current Tax per BOE $/BOE 2.91 2.88 2.98 2.66 1.78 2.07 2.02 1.99 1.91 1.89 1.81 Future taxes12 $MM 3,536 (682) (1,634) 1,367 (3,525) 1,400 2,402 2,369 2,336 1,990 1,790 TOTAL CORPORATE TAXES (After Reconciliation) $MM 9,755 5,598 4,932 7,070 168 5,696 6,619 6,549 6,401 6,057 5,780


Table 4 (cont’d): Aggregate Data For All Regions (Base Case)

2005 2006 2007 2008 2009 2010E 2011E 2012E 2013E 2014E 2015E Payments to Government Federal Income Tax (incl LCT) $MM 4,308 4,238 4,432 3,608 2,049 2,762 2,736 2,538 2,454 2,455 2,439 Provincial Income Tax $MM 1,911 2,042 2,134 2,095 1,644 1,534 1,481 1,642 1,611 1,612 1,551 Crown Royalties $MM 14,409 13,265 13,596 18,833 8,767 11,219 13,552 14,454 14,778 14,910 15,274 Land Sales $MM 2,720 2,660 2,377 5,195 2,152 3,800 2,781 2,578 2,646 2,747 2,884 Total Payments to Government $MM 23,348 22,205 22,540 29,731 14,612 19,315 20,550 21,212 21,489 21,724 22,148 Cash Expenditures Total Outlays $MM 21,868 25,863 27,090 31,069 33,370 34,065 35,970 38,209 40,871 43,614 46,722 Average per Unit $/BOE 10.25 11.85 12.28 14.52 16.09 16.39 17.24 18.22 19.22 20.22 21.16 Interest $MM 2,388 2,507 3,442 4,328 5,213 4,076 4,155 4,243 4,331 4,419 4,507 Interest per Unit $/BOE 1.12 1.15 1.56 2.02 2.51 1.96 1.99 2.02 2.04 2.05 2.04 Cash Flow After Tax Cash Flow $MM 62,387 53,512 57,122 83,255 36,664 45,142 55,613 57,331 57,231 56,240 55,855 Average per Unit $/BOE 29.24 24.52 25.90 38.90 17.68 21.71 26.65 27.35 26.92 26.07 25.30 Non-Cash Charges Depreciation/Depletion $MM 21,129 23,052 26,591 28,966 26,251 26,311 26,413 26,535 26,907 27,300 27,941 Average per Unit $/BOE 9.90 10.56 12.06 13.53 12.66 12.66 12.66 12.66 12.66 12.66 12.66 Other $MM 4,009 2,103 3,838 7,515 2,783 2,783 2,783 2,783 2,783 2,783 2,783 Net Income After Tax Net income $MM 33,714 29,039 28,327 45,407 11,154 14,647 24,015 25,644 25,205 24,166 23,340 Profitability Capital Employed $MM 231,485 301,834 311,997 349,103 320,974 340,447 367,985 397,404 426,670 455,394 483,943 Total Equity $MM 124,761 178,628 187,063 205,593 183,715 199,791 219,319 241,331 263,860 287,878 313,626 ROCE % 16.7% 9.9% 9.3% 14.3% 3.5% 5.6% 8.0% 7.8% 7.2% 6.5% 5.9% ROE % 27.0% 16.3% 15.1% 22.1% 6.1% 7.3% 10.9% 10.6% 9.6% 8.4% 7.4% Capital Investment Exploration $MM 8,719 9,390 7,369 10,213 5,337 10,311 9,184 9,391 9,539 9,905 10,371 Development $MM 23,742 27,202 22,924 24,394 15,023 20,880 23,073 24,244 24,386 25,320 26,449 Northern Canada and East Coast $MM 2,354 1,982 1,357 1,687 1,975 2,829 3,207 2,687 2,071 2,151 2,078 Total Traditional $MM 34,815 38,574 31,650 36,293 22,335 34,020 35,464 36,323 35,996 37,375 38,899 Oil Sands $MM 10,437 14,337 18,065 18,113 11,227 13,000 15,000 17,000 18,500 19,500 21,000 TOTAL INVESTMENT $MM 45,252 52,911 49,716 54,406 33,562 47,020 50,464 53,323 54,496 56,875 59,899 Total Reinvest. Ratio % 73% 99% 87% 65% 92% 104% 91% 93% 95% 101% 107%


Table 5: Data for Alberta Only (Base Case)

2005 2006 2007 2008 2009 2010E 2011E 2012E 2013E 2014E 2015EProduction/Sales Traditional Oil & Liquids MBOE/d 1,198 1,184 1,157 1,101 1,025 1,003 980 957 942 934 935 Oil Sands MBOE/d 992 1,126 1,199 1,207 1,331 1,482 1,612 1,763 1,917 2,049 2,176 Natural Gas MMCf/d 13,234 13,178 13,127 12,375 11,448 10,804 10,160 9,558 9,129 8,828 8,699 TOTAL MBOE/d 4,395 4,507 4,544 4,371 4,265 4,286 4,286 4,313 4,380 4,454 4,561 % AB Production of Total Cdn Production % 75% 75% 75% 75% 75% 75% 75% 75% 75% 75% 75% % of Total BOE Traditional Oil & Liquids % 27% 26% 25% 25% 24% 23% 23% 22% 22% 21% 20% Oil Sands % 23% 25% 26% 28% 31% 35% 38% 41% 44% 46% 48% Natural Gas % 50% 49% 48% 47% 45% 42% 40% 37% 35% 33% 32% Revenues Traditional Oil & Liquids $MM 23,470 23,548 24,815 32,211 19,768 22,777 26,238 26,003 25,518 25,236 25,246 Oil Sands $MM 16,127 22,561 25,553 38,102 29,392 37,143 46,103 50,253 53,589 56,232 58,740 Natural Gas $MM 41,445 30,399 29,947 35,908 16,923 14,985 13,899 14,827 15,006 14,988 15,233 TOTAL REVENUES $MM 81,042 76,508 80,315 106,221 66,083 74,904 86,239 91,083 94,113 96,456 99,218 % AB Revenues of Total Cdn Revenues % 74% 74% 73% 73% 74% 75% 75% 76% 77% 77% 77% % of Revenues Traditional Oil & Liquids % 29% 31% 31% 30% 30% 30% 30% 29% 27% 26% 25% Oil Sands % 20% 29% 32% 36% 44% 50% 53% 55% 57% 58% 59% Natural Gas % 51% 40% 37% 34% 26% 20% 16% 16% 16% 16% 15% Royalties Total Traditional Royalties $MM 11,796 9,198 8,071 10,667 3,885 4,440 5,059 5,452 5,601 5,682 5,825 Total Royalties per Unit $/BOE 9.50 7.45 6.61 9.24 3.63 4.34 5.18 5.86 6.23 6.47 6.69 Total Oil Sands Royalties $MM 819 2,187 2,716 3,545 2,110 3,343 4,380 5,025 5,359 5,623 5,874 Total Royalties per Unit $/BOE 2.26 5.32 6.21 8.05 4.34 6.18 7.44 7.81 7.66 7.52 7.39 Operating Costs Total Traditional Op Costs $MM 8,269 9,300 10,098 11,001 11,291 11,008 10,707 10,416 10,263 10,221 10,336 Average per Unit $/BOE 6.66 7.54 8.27 9.53 10.55 10.76 10.97 11.19 11.41 11.64 11.88 Oil Sands Op Costs $MM 6,305 8,051 8,135 11,105 11,781 13,774 15,732 18,058 20,616 23,146 25,810 Average per Unit $/BOE 17.42 19.58 18.59 25.21 24.24 25.46 26.73 28.07 29.47 30.94 32.49 Cash Flow From Operations (Before Tax) Traditional Cash Netback per Unit $/BOE 33.28 25.65 26.36 36.13 14.84 17.63 20.73 22.51 23.09 23.35 23.59 Oil Sands Cash Netback per Unit $/BOE 22.05 26.89 29.99 49.15 26.64 32.84 39.92 37.92 35.13 32.35 29.71 Total Cash Flow $MM 49,325 42,707 45,309 63,374 28,834 35,804 43,723 45,346 45,339 44,694 44,138 Capital Investment Traditional CAPEX $MM 24,916 27,164 21,235 21,474 12,048 19,172 20,214 21,067 20,878 21,678 22,561 Drilling CAPEX per Well $M/Well 864 1,036 1,041 1,244 1,405 1,608 1,688 1,772 1,861 1,954 2,052 Oil Sands CAPEX $MM 10,437 14,337 18,065 18,113 11,227 13,000 15,000 17,000 18,500 19,500 21,000 Total CAPEX $MM 35,353 41,501 39,300 39,587 23,276 32,172 35,214 38,067 39,378 41,178 43,561 % AB CAPEX of Total CAPEX % 72% 70% 67% 59% 54% 56% 57% 58% 58% 58% 58% Well Count (On a Rig-Release Basis) Total Wells (Incl Bitumen) # 19,231 17,457 13,852 11,693 5,773 8,178 8,723 8,837 8,461 8,432 8,419 Bitumen Wells # 1,272 1,220 1,361 1,044 794 1,165 1,215 1,265 1,315 1,365 1,415 % Natural Gas % 83% 81% 78% 73% 71% 55% 42% 37% 37% 37% 36%% Crude Oil (Incl Bitumen) % 17% 19% 22% 27% 29% 45% 58% 63% 63% 63% 64%


Table 6: Data for British Columbia Only (Base Case)

2005 2006 2007 2008 2009 2010E 2011E 2012E 2013E 2014E 2015EProduction/Sales Traditional Oil & Liquids MBOE/d 76 76 70 63 66 66 67 69 71 73 76 Oil Sands MBOE/d - - - - - - - - - - - Natural Gas MMCf/d 2,705 2,845 2,707 2,797 2,761 2,872 2,987 3,166 3,356 3,557 3,770 TOTAL MBOE/d 526 550 522 529 526 545 565 597 630 666 704 % BC Production of Total Cdn Production % 9% 9% 9% 9% 9% 10% 10% 10% 11% 11% 12% % of Total BOE Traditional Oil & Liquids % 14% 14% 14% 12% 12% 12% 12% 12% 11% 11% 11% Oil Sands % 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% Natural Gas % 86% 86% 86% 88% 88% 88% 88% 88% 89% 89% 89% Revenues Traditional Oil & Liquids $MM 1,598 1,550 1,555 1,824 1,241 1,465 1,746 1,800 1,830 1,869 1,918 Oil Sands $MM - - - - - - - - - - - Natural Gas $MM 8,004 6,576 6,407 7,978 4,082 3,983 4,086 4,913 5,516 6,039 6,602 TOTAL REVENUES $MM 9,602 8,126 7,963 9,801 5,323 5,448 5,832 6,712 7,346 7,908 8,520 % BC Revenues of Total Cdn Revenues % 9% 8% 7% 7% 6% 5% 5% 6% 6% 6% 7% % of Revenues Traditional Oil & Liquids % 17% 19% 20% 19% 23% 27% 30% 27% 25% 24% 23% Oil Sands % 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% Natural Gas % 83% 81% 80% 81% 77% 73% 70% 73% 75% 76% 77% Royalties Total Traditional Royalties $MM 1,967 1,444 1,255 1,370 500 492 558 723 826 893 967 Total Traditional Royalties per Unit $/BOE 10.24 7.20 6.59 7.10 2.60 2.47 2.71 3.32 3.59 3.67 3.76 Total Oil Sands Royalties $MM - - - - - - - - - - - Total Oil Sands Royalties per Unit $/BOE - - - - - - - - - - - Operating Costs Total Traditional Op Costs $MM 1,267 1,467 1,504 1,568 1,726 1,824 1,929 2,077 2,238 2,413 2,602 Average per Unit $/BOE 6.59 7.31 7.90 8.12 8.99 9.17 9.35 9.54 9.73 9.93 10.12 Oil Sands Op Costs $MM - - - - - - - - - - - Average per Unit $/BOE - - - - - - - - - - - Cash Flow From Operations (Before Tax) Traditional Cash Netback per Unit $/BOE 30.33 22.91 23.72 31.46 10.88 11.57 11.98 13.66 14.28 14.57 14.93 Oil Sands Cash Netback per Unit $/BOE - - - - - - - - - - - Total Cash Flow $MM 5,827 4,598 4,516 6,074 2,088 2,301 2,471 2,973 3,285 3,542 3,835 Capital Investment Traditional CAPEX $MM 4,934 6,094 5,502 7,880 5,173 6,167 6,418 6,902 7,556 7,863 8,384 Drilling CAPEX per Well $M/Well 2,178 2,630 3,385 4,141 5,147 5,655 5,719 5,833 5,950 6,069 6,190 Oil Sands CAPEX $MM - - - - - - - - - - - Total CAPEX $MM 4,934 6,094 5,502 7,880 5,173 6,167 6,418 6,902 7,556 7,863 8,384 % BC CAPEX of Total CAPEX % 14% 16% 17% 22% 23% 19% 18% 19% 21% 21% 22% Well Count Total Wells # 1,371 1,383 877 854 564 653 667 720 773 787 822 % Natural Gas % 96% 95% 92% 97% 94% 97% 97% 97% 97% 97% 97%% Crude Oil % 4% 5% 8% 3% 6% 3% 3% 3% 3% 3% 3%


Table 7: Data for Saskatchewan Only (Base Case)

2005 2006 2007 2008 2009 2010E 2011E 2012E 2013E 2014E 2015EProduction/Sales Traditional Oil & Liquids MBOE/d 424 433 431 444 429 419 408 403 406 406 408 Oil Sands MBOE/d - - - - - - - - - - - Natural Gas MMCf/d 676 665 566 560 515 489 484 479 474 470 465 TOTAL MBOE/d 537 544 526 537 515 501 489 483 485 485 486 % SK Production of Total Cdn Production % 9% 9% 9% 9% 9% 9% 9% 8% 8% 8% 8% % of Total BOE Traditional Oil & Liquids % 79% 80% 82% 83% 83% 84% 84% 83% 84% 84% 84% Oil Sands % 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% Natural Gas % 21% 20% 18% 17% 17% 16% 16% 17% 16% 16% 16% Revenues Traditional Oil & Liquids $MM 7,405 8,573 9,073 13,912 9,094 10,434 11,813 11,674 11,585 11,469 11,421 Oil Sands $MM - - - - - - - - - - - Natural Gas $MM 2,118 1,533 1,291 1,624 761 678 662 744 780 798 814 TOTAL REVENUES $MM 9,523 10,106 10,364 15,535 9,855 11,112 12,475 12,418 12,365 12,267 12,235 % SK Revenues of Total Cdn Revenues % 9% 10% 9% 11% 11% 11% 11% 10% 10% 10% 10% % of Revenues Traditional Oil & Liquids % 78% 85% 88% 90% 92% 94% 95% 94% 94% 93% 93% Oil Sands % 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% Natural Gas % 22% 15% 12% 10% 8% 6% 5% 6% 6% 7% 7% Royalties Total Traditional Royalties $MM 1,474 1,578 1,434 2,390 1,468 1,731 1,935 1,926 1,918 1,904 1,899 Total Traditional Royalties per Unit $/BOE 7.52 7.95 7.47 12.19 7.82 9.47 10.84 10.92 10.84 10.76 10.71 Total Oil Sands Royalties $MM - - - - - - - - - - - Total Oil Sands Royalties per Unit $/BOE - - - - - - - - - - - Operating Costs Total Traditional Op Costs $MM 1,660 1,794 1,898 1,838 1,863 1,849 1,842 1,856 1,900 1,937 1,981 Average per Unit $/BOE 8.47 9.04 9.89 9.37 9.92 10.12 10.32 10.52 10.73 10.95 11.17 Oil Sands Op Costs $MM - - - - - - - - - - - Average per Unit $/BOE - - - - - - - - - - - Cash Flow From Operations (Before Tax) Traditional Cash Netback per Unit $/BOE 29.77 30.83 33.05 53.58 29.48 37.02 44.49 44.66 43.96 43.26 42.77 Oil Sands Cash Netback per Unit $/BOE - - - - - - - - - - - Total Cash Flow $MM 5,836 6,122 6,341 10,505 5,536 6,768 7,942 7,876 7,779 7,654 7,585 Capital Investment Traditional CAPEX $MM 2,356 2,851 3,127 4,765 2,757 5,234 4,991 5,086 5,037 5,242 5,459 Drilling CAPEX per Well $M/Well 411 476 581 621 970 1,138 1,195 1,254 1,317 1,383 1,452 Oil Sands CAPEX $MM - - - - - - - - - - - Total CAPEX $MM 2,356 2,851 3,127 4,765 2,757 5,234 4,991 5,086 5,037 5,242 5,459 % SK CAPEX of Total CAPEX % 7% 7% 10% 13% 12% 16% 14% 14% 14% 14% 14% Well Count Total Wells # 3,767 3,825 3,397 4,018 1,771 2,770 2,675 2,596 2,449 2,427 2,407 % Natural Gas % 49% 43% 36% 32% 20% 7% 7% 7% 7% 7% 7%% Crude Oil % 51% 57% 64% 68% 80% 93% 93% 93% 93% 93% 93%


Footnotes

1. British Columbia, Alberta and Saskatchewan, are the major oil and gas producing provinces in Canada. The “Rest of Canada” category is dominated by Newfoundland and Nova Scotia, but also includes Manitoba and the Territories.

2. This page discusses taxes and royalties paid by exploration and production companies only. Taxes paid by oilfield service companies and other corporate entities associated with the upstream oil and gas business are not included in the current income tax value.

3. The industry’s Weighted Average Cost of Capital (WACC) is calcu-lated using the Capital Asset Pricing Model (CAPM) methodology.

4. The number of wells drilled per year used in this report is on a rig-release basis, not on a completion basis.

5. Average finding and development costs for the industry on page 46 are calculated by dividing the estimated, traditional reserve additions for each year into the capital expended in the same year. Reserve ad-ditions used are those captured by CAPP on page 43. Note that these additions are on an established basis and do not include the oil sands. Nor do they include future development capital. Because reserve ad-ditions used on page 46 are established, F&D costs will appear higher than on page 47, where proven and probable F&D costs from a sample set of publicly traded companies are shown.

6. Only mid-cap companies (5,000 to 20,000 BOE/d of production) and small-cap companies (500 to 5,000 BOE/d of production) are shown. Large companies, with production greater than 20,000 BOE/d most often have operations beyond Canada, and so reported average F&D costs are often not purely representative of Canadian operations.

7. Return on capital employed (ROCE) is estimated by taking the total earnings of the industry, plus its future taxes, plus its after-tax interest,

and dividing the total by the average amount of capital employed (total assets less current liabilities).

8. Return on equity (ROE) is estimated by taking the earnings of the industry and dividing it by its average shareholders’ equity (common book equity, retained earnings and contributed surplus).

9. Value creation is calculated by taken the industry’s return on capital employed in a particular and subracting the corresponding cost of its capital (WACC). Notionally, if the industry can’t generate a return on the capital that it invests that is greater than the cost of its invested capital (i.e. create positive value), then there is little incentive for sustained future investment.

10. The matrix in Tables 1, 2 and 3, is dominantly a function of the dif-ferent oil and gas prices in the grid. Few other variables change in the economic model. For example, input costs for oil sands operations do vary with the three natural gas price sensitivities.

11. A Reconciliation of Estimated Permanent Differences line item is necessary to match industry level, “top-down” tax calculations with a control group of corporate financial statements. This method ties the economic model of the industry to actual corporate data.

12. Canadian public corporations will have to transition to Interna-tional Financial Reporting Standards (IFRS) from Canadian GAAP for preparation of Financial Statements in 2011. These accounting changes will impact the timing and recognition of certain temporary and permanent differences between book value and tax pools. How individual companies adopt these new accounting policies will impact their corporate tax positions. It is difficult to estimate an average industry tax expense until such time as there is more historical IFRS financial statement data to analyze.


Glossary

Barrel of Oil Equivalent (BOE): The current con-version for 1,000 cubic feet of natural gas to barrels of oil equivalent is 6:1, unless otherwise noted. NGLs are considered to be commingled with oil (see “Natural Gas Liquids”). Sulphur revenue is not included in BOE figures. Base Case: Forecast based on futures curve pricing for WTI and AECO as of December 31, 2010.Barrel: A unit of volume often associated with oil and oil products. The equivalent of 42 US gallons or about 160 litres.Bitumen: Petroleum in semi-solid or solid forms.Established Reserves: The portion of the discov-ered resource base that is estimated to be recover-able using known technology under present and anticipated economic conditions. Includes proved plus a portion of probable (usually 50%). Finding and Development Costs (F&D): Capital expenditures (costs less capitalized G&A) divided by reserve additions and revisions (proved, gross, traditional), unless otherwise noted.Fiscal Pulse: The dynamic character and amount of capital that flows through the upstream oil and gas industry in a year.Focus Period: The years 2005 to 2010 inclusive.Forecast Period: The years 2011 to 2015 inclusive.GJ: Abbrevation for gigajoule, a unit of energy.General and Administrative Costs (G&A): Expensed and capitalized overhead costs, unless otherwise noted.Gross Revenues: Revenues realized by an oil and gas company before royalties have been deducted.

Horizontal Drilling: Drilling a well that deviates from the vertical and travels horizontally through a hydrocarbon bearing geologic formation. Hydraulic Fracturing: The shattering of subsur-face geologic formations using extremely high pressure fluids pumped down a well bore. Used to stimulate and enhance the flow of oil and gas production.Natural Gas Liquids (NGLs): Liquids obtained during natural gas production, including ethane, propane, butanes and condensate.Mcf: A thousand cubic feet.MMBtu: A million British Thermal Units, a unit of energy. Oil Sands: Large scale deposits of sand saturated with bitumen found in east central Alberta.Operating Costs: Production (lifting costs), and general and administrative costs related to oil and gas operations.Resource Play: A type of play developed over a long period of time in a large-scale operation. Resource plays are often associated with tight oil and gas formations and therefore have unique geological and commercial development attributes. Horizontal drilling and hydraulic fracturing tech-nologies have recently opened up vast new resource plays. Return on Capital Employed (ROCE): The earnings of the industry, plus its future taxes, plus its after-tax interest, divided by the average amount of capital employed (total assets less cur-rent liabilities).

Return on Equity (ROE): The earnings of the industry divided by its average shareholders’ equity (common book equity, retained earnings and con-tributed surplus).Royalty: The owner’s share of production or rev-enues retained by the government or by freehold mineral rights holders. Royalties are calculated from several variables, including total production, commodity price and well depth. Shale: A type of tightly packed, but brittle rock formed from clay. Commonly associated with resource plays.Stakeholders: Any person, organization or cor-poration with an interest in oil and gas activities. They may include landowners, municipalities, aboriginal communities, financial institutions, regulators, environmental groups, governments and related industries.Synthetic Crude Oil: A mixture of hydrocarbons, similar to crude oil, derived by refining or “upgrad-ing” bitumen from the oil sands into lighter grades of oil. Tight gas: Natural gas found in hard rock, sandstone, shale or limestone formations that are impermeable and non-porous. Extracting tight gas usually requires enhanced technology such as “hydraulic fracturing”. Typically associated with resource plays.Tight oil: Oil found in a petroleum-bearing for-mation of relatively low porosity and permeability.Traditional oil and gas: Any upstream oil and gas operation that excludes oil sands. Typically associ-ated with resource plays.

62


About CAPP

63

This study was sponsored in part by the Canadian Association of Petro-leum Producers (CAPP), which is the voice of Canada’s upstream oil and natural gas industry.

Mission Statement CAPP’s mission is to enhance the economic sustainability of the Ca-

nadian upstream petroleum industry in a safe and environmentally and socially responsible manner, through constructive engagement and com-munication with governments, the public and stakeholders in the commu-nities in which we operate.

Profile CAPP represents companies, large and small, that explore for, develop

and produce natural gas and crude oil throughout Canada. CAPP’s mem-ber companies produce more than 90 per cent of Canada’s natural gas and crude oil. CAPP’s associate members provide a wide range of services that support the upstream crude oil and natural gas industry. Together CAPP’s members and associate members are an important part of a national indus-try with revenues of about $100 billion-a-year.

The Statistical HandbookThis report was made possible in large part by data provided in CAPP’s

Statistical Handbook. The Statistical Handbook, available at www.capp.ca, is a comprehensive compilation of the upstream petroleum industry’s progress, summarizing broad statistical information concisely in one pub-lication. The handbook features drilling, reserves, production, pricing and other current and historical data. CAPP has been producing the handbook since 1955; some of the statistics – such as oil production figures – date back to 1947.

Please note that CAPP does not warrant the accuracy of the data in the handbook and please read the disclaimer and limitations on use of the handbook that is displayed prominently with the handbook.

Contact Canadian Association of Petroleum Producers 2100, 350 - 7 Avenue SW Calgary, Alberta, Canada T2P 3N9

Phone: (403) 267-1100

Website: www.capp.ca

This publication is available electronically at www.arcfinancial.com and www.capp.ca

Documents

ARC Report - Turmoil and Renewal