The Evolution of Royalty Systems in Albertaâ€™s Oil Sands: An

The Evolution of Royalty Systems in

Alberta’s Oil Sands: An Overview

André Plourde

Department of Economics, University of Alberta

EXPERT WORKSHOP ON ESTIMATING SUPPORT TO FOSSIL FUELS

Environment & Trade and Agriculture Directorates

and Centre for Tax Policy and Administration, OECD

Paris, 18-19 November 2010

Foreword

Thanks to Departments of Energy and

of Finance & Enterprise (Government

of Alberta) for permission to use some

of the information included in the

analysis

Please note that I was a member of

Alberta’s Royalty Review Panel of

2007

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OECD - Estimating Support to Fossil

Fuels 2

Roadmap

Context

Production ◦ Bitumen & Synthetic crude oil (SCO)

Oil Sands Taxes & Royalties ◦ Changes over time

Observations #1

Simulation Exercises ◦ Model descriptions

◦ Key assumptions

◦ Output

Simulation Results ◦ Royalties

◦ ACCA

Observations #2

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Context

Constitutional context ◦ Ownership rights to natural resources located

within boundaries of a province are vested in that province…applies to oil sands Some exceptions (e.g., First Nations reserves,

national parks)

These rights have mostly not been alienated In oil sands, some 97% of remaining reserves owned by

the people of Alberta

Three “oil sands areas” in Alberta ◦ Defined by provincial legislation

◦ ALL crude oil production within OSAs deemed to be “oil sands” production


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Production: Bitumen

Total bitumen production in 2009 ◦ 236.7 thousand cubic metres per day (Mcm/d)

About 70% of Alberta crude oil production

Two families of technologies (2009 production)

IN SITU (105.5 Mcm/d – 45% of bitumen production)

Steam-assisted gravity drainage (SAGD; 37%)

Cyclic steam stimulation (CSS; 32%)

Primary (31%)

Experimental ( < 1%)

SURFACE MINING (131.2 Mcm/d – 55%)

Suncor + Syncrude (99.1 Mcm/d ~ 40% of total prod’n)

Source: ERCB ST98-2010 (2010, Section 2)


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Production: Upgraded (SCO)

Total synthetic crude oil production in 2009

◦ Integrated with bitumen production

4 linked with surface mining projects

1 (new, smaller) linked with in situ project

◦ 211.6 Mcm/d

Suncor + Syncrude (90.6 Mcm/d – 75% of total)

Total non-upgraded bitumen production in 2009

◦ 90 Mcm/d

◦ Bitumen “losses” due to upgrading

~25 Mcm/d (12% of bitumen production)

Source: ERCB ST98-2010 (2010, Section 2)


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Taxes & Royalties

FEDERAL

◦ Federal government levies a corporate income tax (CIT) on all for-profit companies

PROVINCIAL

◦ Government of Alberta uses four instruments CIT (essentially same base as federal, but rate differs)

Bonus bids (payments) – “leasing” production rights

Rentals – linked to land registry system (negligible)

Royalties – two types: base & net revenue royalties

LOTS of changes in regime since beginning of operations in early 1960s


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Taxes & Royalties: Evolution

Prior to 1992…

◦ Gratis allocation of OS production rights

NO bonus bids collected by province

From 1992 on…

◦ Bonus bids for OS production rights result from first-price auctions

But relatively small values per hectare

Prior to 1997…

◦ Province & producer negotiate royalty agreements for each project separately – three such agreements

Suncor, Syncrude – integrated projects, royalties on SCO

Imperial Cold Lake – in situ bitumen

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Prior to 1997… ◦ OS surface mining treated as “mining” for CIT purposes &

thus ACCA available (linked to project revenues)

◦ OS in situ treated as “petroleum” for CIT purposes & thus ACCA NOT available

◦ Royalties not deductible in calculation of CIT payments Instead “resource allowance” (25% of net operating revenues)

deductible (more generous to OS producers than royalty deduction)

1993… ◦ Federal & Alberta governments + industry set up National

Oil Sands Task Force (NOSTF)

◦ Two key sets of issues “Individual” nature of royalty system – disincentive to investment

More upside potential for in situ – ACCA treatment

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1995… ◦ Recommendations included in NOSTF report

◦ ADOPT A “GENERIC” ROYALTY REGIME Based on Garnault & Clunies-Ross (1975) – Resource Rent

Tax “Revenue – Cost” approach to royalties

Royalties payable only after “payout” at rate of 25% to 30% of “net revenues”

Cumulate eligible expenditures at long-term government bond rate (LTBR) + 2%

Royalty to be payable on bitumen

◦ EXTEND ACCA TO ALL OIL SANDS PROJECTS Both surface mining & in situ projects

Remove ring fence on ACCA - allow deduction against ALL company income

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1997… ◦ Response of Governments of Canada & Alberta

◦ ROYALTIES Adopt a “generic” system

Royalties payable in cash

Base royalty of 1% on value of production

Net revenue royalty at 25% of “net revenues” after payout Base royalty a “credit” (not a “deduction”) in calculation of NRR

Cumulate eligible expenditures (including base royalty payments) at LTBR

Major expansions can bring project out of “payout”

Royalties payable on bitumen or SCO – producer choice Expenditures related to upgrading only eligible if royalties paid on SCO

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1997… ◦ Response of Governments of Canada & Alberta

◦ CORPORATE INCOME TAX Extend ACCA to ALL oil sands projects

BUT…maintain project-related ring fence

◦ ISSUE: What to do about existing arrangements? “Crown Agreements”: Suncor, Syncrude, Imperial &

province

Essentially, “freezing” royalty (& tax) systems at the pre-1997 configurations for a period, then generic system to apply Until 31 December 2014 for Suncor & Syncrude; 31 Dec. 2008 for

Imperial

Designed so that an act of the Legislature (almost) needed to change these

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1997…

◦ What to do about existing arrangements? In Crown Agreements, Suncor & Syncrude given right to

elect to pay royalties on BITUMEN prod’n as of 1 January 2009

If elect to pay on bitumen, then “compensatory payments” owed to the province to compensate for the fact that upgrading-related spending considered eligible expenditures for purposes of net revenue royalties

PROBLEM: since these are integrated projects & bitumen “sales” are internal transactions, how to assign a “price” to the bitumen (needed to calculate royalties)?

“Bitumen Valuation Methodology” to be determined by government six months prior to “royalties on bitumen” coming into force

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Getting to the March 2007 federal budget…

◦ LARGE reductions in both Alberta & federal CIT

rates

Alberta: 15.5% → 10%

Federal: 29.12% → 18.5%

In a subsequent budget, Government of Canada indicated its

intention to reduce CIT rate to 15%

◦ Royalty deductibility replaces resource allowance

Recall “double dipping” for Syncrude

◦ In March 2007 budget, federal gov’t announces

phasing out of ACCA for ALL new OS projects

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Taxes & Royalties: Evolution September / October 2007…

◦ Report of Alberta’s Royalty Review Panel

◦ Gov’t of Alberta’s New Royalty Framework

Base royalty rate: 1% to 9%

Net revenue royalty rate: 25% to 40%

◦ Low end if (current-dollar) price of WTI ≤ $(Cdn)55

◦ High end if price of WTI ≥ $(Cdn)120

◦ Linear interpolation in between

Royalties to be paid in kind – Bitumen Royalty in Kind (BRIK)

“Negotiated” higher royalties for Suncor & Syncrude and earlier termination (2012) of Crown Agreement provisions

◦ And exception for these two to BRIK provisions

Provincial part of ACCA to be phased out (as with federal part)

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Observations #1

Royalty & tax system applicable to OS “always” structured to leave some of the (even ex ante) rents to producers – especially when payout occurs

◦ For example, net revenue royalty rate never higher than 40%

Base royalty acts to discourage some high-cost projects – especially if payout unlikely to occur (& more so with post-2007 system)

Fact that base royalty is a credit (& not a deduction) in calculation of net revenue royalty JOINTLY with fact that major expansions can send projects “out of payout” provides incentives to “speed up” expansions to reduce royalty payments – expand to delay onset of net revenue royalty

◦ A factor in the sharp “cost” increases observed in 2006-08??

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Simulation Exercises

First, focus on changes in royalties

◦ 2007 version of “generic” regime – GENERIC

◦ New Royalty Framework – NRF

◦ Initially, CIT components identical in both cases no ACCA, CIT rates = 15% (federal) + 10% (Alberta)

Then, look at consequences of ACCA (using NRF)

◦ No ACCA

◦ Federal + Provincial ACCA, with ring fence

◦ Federal + Provincial ACCA, without ring fence

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Simulation Models: Description

Discounted cash flow models (Plourde 2009, 2010)

◦ SAGD at Cold Lake; surface mine at Athabasca

◦ Information on capital expenditures, non-energy operating expenditures, energy use (natural gas, electricity), bitumen production profiles Exogenous import contents

◦ Assumptions about Canada-US exchange rate, inflation rate, LTBR

◦ Key price: WTI in US $ From that, use historical averages to obtain bitumen

price & price of natural gas

Natural gas price then drives electricity price

◦ LOTS of detail on royalties & taxes

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Simulation Models: Key Assumptions

SAGD

Construction begins 2010

First production 2014

Last production 2043

Peak prod’n 60,000 bbls/d

Total prod’n 569 MMbbls

Total capex $2.4 B (2010$)

Total opex $6.2 B (2010$)

at WTI price of $70 (US)

(Capex+opex)/bbl $14.99

Bitumen price $40.53

Surface Mine

Construction begins 2010

First production 2015

Last production 2045

Peak prod’n 200,000 bbls/d

Total prod’n 2256 MMbbls

Total capex $8.9 B (2010$)

Total opex $21.0 B (2010$)

at WTI price of $70 (US)

(Capex+opex)/bbl $13.22

Bitumen price $33.16

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Simulation Models: Output

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-200

0

200

400

600

800

1000

1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39

mil

lio

ns

of

20

10

$

year

Surface Mine, Revenues to Governments, NRF no ACCA WTI=$(US)70; 1/pfx=0.95

Total CIT Bonus+Rentals Base Royalty Net Revenue Royalty

Results: Royalties

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30

35

40

45

50

55

60

50 55 60 65 70 75 80 85 90 95 100 105 110 115 120

Pro

du

cer

Sh

are

of

NP

V

WTI price in real (2010) US dollars per barrel

Estimated Producer Shares of NPV, no ACCA

SAGD - Generic SAGD - NRF

Mine - Generic Mine - NRF

For given CIT

provisions, NRF

marks an increase in

“government take”:

Estimated share of

project NPVs accruing

to producers lower for

both SAGD & mining

projects

On average, estimated producer share of NPV under NRF 10.1

percentage points lower for SAGD; 11.8 percentage points lower for

surface mine

Until WTI prices of about $(US)90, estimated producer share of NPV

LOWER for surface mining projects under both royalty regimes

effect more pronounced at lower prices under NRF

Results: ACCA, SAGD / NRF

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42

43

44

45

46

47

48

49

50 60 70 80 90 100 110 120

Pro

du

cer

Sh

are

of

NP

V


Estimated Producer Shares of NPV, SAGD under NRF

no ACCA

F+P ACCA

No Ring Fence

NOTE SCALE

Under NRF, rather

small differences in

estimated producer

share of NPV from

SAGD projects as

assumptions about

ACCA changed

at most 1.5 percentage

points At lower prices, much of the difference can

be traced back to whether or not ACCA

provisions include a project-specific ring

fence

Results: ACCA, Mine / NRF

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30

32

34

36

38

40

42

44

50 60 70 80 90 100 110 120

Pro

du

cer

Sh

are

of

NP

V


Estimated Producer Shares of NPV, Surface Mine under NRF

no ACCA

F+P ACCA

no ring fence

NOTE SCALE

Under NRF,

differences in

estimated producer

share of mining

project NPVs much

larger as assumptions

about ACCA changed

as much as 6

percentage points Differences particularly pronounced at lower

WTI prices and when there is no ring fence to

the assumed ACCA provisions

Differences much smaller at WTI prices of

about $(US)90 and above

Observations #2

For given CIT provisions, NRF provides weaker incentives for high-cost / low-NPV projects to go ahead than did GENERIC system that it replaced

◦ Especially at lower prices & in the case of surface mining projects (which are “larger” and more capital-intensive than SAGD projects)

ACCA not worth a lot to SAGD producers

◦ Under both GENERIC and NRF; at whatever prices; whether or not there is an ACCA ring fence

BUT…ACCA clearly worth more to surface mine producers, but only if there is no ring fence & then only at lower prices

◦ With ring fence provision, seems unlikely to accelerate development

◦ Results of METR calculations (e.g., Royalty Review Panel & others)? Is this about ring fence provision?

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Observations #2

Overall, for given CIT provisions, NRF seems to extend more favorable treatment (from producers’ perspective) to smaller, less capital-intensive SAGD projects than to surface mining projects ◦ Especially at lower prices (i.e., WTI prices of less than

$(US)90)

◦ To be viewed in context of fact that more than 80% of remaining reserves of bitumen in Alberta can only be produced using in situ techniques (deposits too deep to be accessed by surface mines)

As individual arrangements / special deals are wound up, system that emerges estimated still to leave a substantial part of the economic rent with OS producers, but also seems to provide more incentives for producers to manage capital expenditures – especially in the case of surface mines

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Observations #2

Finally, three questions…

◦ Can decision to levy OS royalties in kind encourage

inefficient upgrading in Alberta? How much downward

pressure will it exert on bitumen prices?

◦ How important are the royalty-induced incentives for

accelerated project expansions?

Because of structure of net revenue royalty provisions, these

are clearly stronger under NRF than under GENERIC – but

how much does it matter?

◦ Are there X-efficiency / cost-minimization types of issues

inherent in “revenue – cost” royalty regimes?

And if so, how important are these?

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Documents

The Evolution of Royalty Systems in Albertaâ€™s Oil Sands: An