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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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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Taxes & Royalties: Evolution
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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Taxes & Royalties: Evolution
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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Taxes & Royalties: Evolution
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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Taxes & Royalties: Evolution
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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Taxes & Royalties: Evolution
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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Taxes & Royalties: Evolution
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
WTI price in real (2010) US dollars per barrel
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
WTI price in real (2010) US dollars per barrel
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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