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Modernized Royalty Framework (MRF) 2017 1
Modernized Royalty
Framework (MRF)
2017
1
Disclaimer
This presentation is for informational purposes only, pending
approval of the:
• Petroleum Royalty Regulation 2017
• Natural Gas Royalty Regulation 2017
• Oil Sands Royalty Regulation, 2009
• Enhanced Hydrocarbon Royalty Regulation
• Emerging Resources Royalty Regulation
• Mines and Minerals Administration Regulation
Contents of this document may be subject to change.
Note:
Throughout this presentation there are a number of
examples which may include rounding of calculation in order
to simplify presentation of the material. 2
Outline1. High level overview of MRF
2. Drilling and Completion Cost Allowance (C*)
3. Post-C*
• Revenue drawdown
• Post-C* royalty formulas
4. Actual drilling and completion cost reporting for ACCI
5. Questions
4
5
MRF Overview - Historical ContextRoyalty Review Process
Advisory Panel
Work and Final
Report
Fall/Winter 2015
Release of
Calibration
Formulas
April 2016
Industry Training
Sessions
Fall/Winter
2016
New
Framework
takes effect
January 2017
Strategic Overlays,
Detailed Rules
Spring/Summer
2016
Modernized Royalty Framework (MRF)
• Applies to conventional oil, gas and gas by-products,
and non-project oil sands wells
• Apply to wells spud on or after January 1 2017; (and
early opt-in)
January 2017 Production Month – GO LIVE
• Emulates a “revenue minus costs” approach
High Level Changes - MRF
• ARF– All programs and ARF formula only apply to wells spud on or before
December 31, 2016
– Benefits continue until they run out or when the regulation expires on
December 31, 2026
• MRF– Applies to wells spud on or after January 1, 2017; early opt-in and
ARF wells re-entered on or after January 1, 2017
– R<C*: 5% flat royalty rate
– R≥C*: Post-C* formulas Rp + Rq (includes maturity threshold)
• 2 new programs
– Emerging Resources Program (ERP)
– Enhanced Hydrocarbon Recovery Program (EHRP)
6
Non-Project Royalty (NPR) Wells
• NPR wells may be allowed to form part of an oil
sands Project provided:
– An OSR application has been submitted within 12
months of MRF production
– OSR approval has been granted
– Royalty payable has been adjusted accordingly
7
What is C* ?
8
C*= ACCI * ((1170 * (TVD - 249))
+ (3120 * (TVD - 2000))+ (Y * 800 * TLL)+ (0.6 * TVDa * TPPe))
+ C* Outline1. Definitions2. Formulas3. Revenue
Definition of Terms
Alberta Capital Cost Index (ACCI)
• Purpose is to capture changes in drilling and
completion costs over time
• Calculated annually and released by the end of July
and becomes effective the following January 1
• Can change by a maximum of plus or minus 5% year
to year
• 2017 and 2018 the ACCI will be 1.0
• ACCI will be determined by Alberta Energy based on
the information provided by industry9
Drilling and Completion Cost Allowance (C*)
The well variables that are used to determine C* are:
- TVD - True Vertical Depth
- TLL - Total Lateral Length
- TPPe - Total Proppant Placed Equivalent
These variables are used to calculate a C* dollar
amount to recognize a proxy of drilling and completion
costs.
C* is calculated at the licence level.
Production from all events draws down the C*
10
Definition of Terms
Defintion of Terms
True Vertical Depth (TVD) – is the true vertical depth of a well
in metres determined by measuring the vertical distance in metres in a
perpendicular line from the kelly bushing of a well to the base of the
deepest drilled leg
11
Definition of Terms
Total Lateral Length (TLL) - the total lateral length of a
well in metres
12
Total Proppant Placed Equivalent (TPPe) - the total
proppant placed in a well in tonnes as determined by the
Minister using the records of the AER and the proppant
equivalent prescribed by the Minister
Proppant information will be required for each leg fractured
13
Definition of Terms
Proppant Equivalency Table
Equivalency Factor
1
1.5
2.5
Type of Completion
Sand (tonnes)
Resin Coated Sand (tonnes)
Engineered/Manufactured (tonnes)
Acid (m3) = Acid concentration * 10
7.5% concentration 0.75
15% concentration 1.5
28% concentration 2.8
Definition of Terms
Total Proppant Placed Equivalent Examples
14
Proppant Equivalency Table Examples
Equivalency Factor Volume TPPe
1 700 tonnes 700
1.5 700 tonnes 1050
Type of Completion
Sand (tonnes)
Resin Coated Sand (tonnes)
Engineered/Manufactured (tonnes)
2.5 700 tonnes 1750
Acid (m3) = Acid concentration * 10
7.5% concentration 0.75 500m3 375
15% concentration 1.5 500m3 750
28% concentration 2.8 500m3 1400
Definition of Terms
Y Factor - the linear factor for multi-leg wells,
determined in accordance with the following formula:
• Y = 1.39 – (0.04 * (TMD/TVDa))
• Y can range from 0.24 to 1.0
• If Y is calculated
greater than 1,
the Y will equal
1.00
• If Y is calculated
less than 0.24,
the Y will equal
0.2415
Y Factor
Data Requirements to Calculate C*
• When data elements are not provided, that element
will default to zero
• If TVD is not reported, C* will default to zero
• When this data is subsequently provided, a C* will be
calculated and royalty rate will be recalculated
16
17
C*= ACCI * ((1170 * (TVD - 249)) + (3120 * (TVD - 2000)) + (Y * 800 * TLL)
+ (0.6 * TVDa * TPPe))
• The ACCI is used to adjust the C* by a maximum of plus or minus 5% on a yearly basis
• For 2017 and 2018 the ACCI will be set to 1.00
Formula Breakdown
C*= ACCI * ((1170 * (TVD - 249)) + (3120 * (TVD – 2000)) + (Y * 800 * TLL) + (0.6 * TVDa * TPPe))
• $1,170 for every metre drilled vertical from 249m to 2000m• If TVD is less than 249m this part will default to 0• $4,290 for every metre drilled deeper than 2000m
C*= ACCI * ((1170 * (TVD - 249)) + ((3120 * (TVD - 2000)) + (Y * 800 * TLL) + (0.6 * TVDa * TPPe))
• $800 for every metre drilled laterally unless the Y factor is less than 1• For example, if the Y factor is 0.75, $600 for every metre drilled laterally
18
C*= ACCI * ((1170 * (TVD - 249)) + ((3120 * (TVD -
2000)) + (Y * 800 * TLL) + (0.6 * TVDa * TPPe))
• “TVDa” is the average of the true vertical depths of all
drilled legs
Formula Breakdown
Proppant Equivalency Table
Equivalency Factor
1
1.5
2.5
Type of Completion
Sand (tonnes)
Resin Coated Sand (tonnes)
Engineered/Manufactured (tonnes)
Acid (m3) = Acid concentration * 10
7.5% concentration 0.75
15% concentration 1.5
28% concentration 2.8
Formulas for New Wells
There are two formulas for calculating C*:
1. C* for wells ≤ 2000m TVDC*= ACCI * ((1170 * (TVD – 249)) + (Y * 800 * TLL) +(0.6 * TVDa *TPPe))When to use:Wells spud on or after January 1, 2017 or for approved early opt-in wells
2. C* for wells > 2000m TVDC*= ACCI * ((1170 * (TVD - 249)) + (3120 * (TVD - 2000)) + (Y * 800 *TLL) + (0.6 * TVDa * TPPe))When to use:Wells spud on or after January 1, 2017 or for approved early opt-inwells
19
Example Calculation of a Well with A TVD ≤ 2000M
Scenario: A new multi-leg well spud on June 15, 2017 with a TVD =
701m, TLL = 7610m, TMD = 8096m and TPP = 2945 tonnes of sand
3 Steps to calculate C*
1. Calculate the Y FactorY = 1.39 – (0.04 * (TMD/TVDa)) = 1.39 – (0.04 * (8096/701)) = 0.93
2. Calculate the Proppant Equivalency
= 2945 * 1.0 = 2945
3. Calculate the C*C* = ACCI * ((1170 * (TVD – 249)) + (Y * 800 * TLL) + (0.6 * TVDa * TPPe))= 1.00 * ((1170 * (701– 249)) + (0.93 * 800 * 7610) + (0.6 * 701 * 2945))= 1.00 * (528,840 + 5,661,840 + 1,238,667) = $7,429,347
20
Example Calculation of a Well with A TVD > 2000M
Scenario: A new single leg well spud on June 15, 2017 with a TVD = 4724m, TLL =
1486m, TMD = 6210m and TPP = 965 tonnes of engineered sand
3 Steps to calculate C*
1. Calculate the Y FactorY = 1.39 – (0.04 * (TMD/TVD)) = 1.39 – (0.04 * (6210 / 4724)) = 1.34 Due to Y being greater than 1, Y defaults to 1.00
2. Calculate the Proppant Equivalency
= 965 * 2.5 = 2412.5
3. Calculate the C*C* = ACCI * ((1170 * (TVD – 249)) + (3120 * (TVD - 2000)) + (Y * 800 *TLL) +(0.6 * TVDa * TPPe)) = 1.0 * ((1170 * (4724 – 249)) + (3120 * (4724 – 2000) + (1.00 * 800 * 1486) + (0.6 * 4724 * 2412.5)) = 5,235,750 + 8,498,880 + 1,188,800 + 6,837,990 = $21,761,420
21
Re-EntryFor the purpose of C* calculation re-entry:
• Is any drilling or fracture operation in an existing well bore resulting in
a change to TVD, TLL or TPPe
22
Re-Entry ARF Wells• When an ARF well bore is re-entered after Jan 1, 2017, the incrementalactivity is subject to MRF and a C* is calculated based on that activity only• The whole well bore will switch from ARF to MRF until the incrementalC* is drawn down completely• All revenue from that well bore draws down the incremental C* from thetime of the incremental activity• Once the C* is completely drawn down, the well bore reverts back toARF
23
2017 2024 2010
• Well spud
• Well will pay
royalty under
the ARF
royalty
regime
• Re-entry to well
• Well will receive a
C*
• Whole well bore
switches to MRF
royalty regime until
C* is drawn down
to 0
• Well will pay 5%
royalty for all
products
• C* is drawn
down to 0
• Whole well
bore will
revert back to
ARF royalty
regime
Re-Entry ARF Wells – Cont’d
Re-Entry MRF Wells
• When an MRF well bore is re-entered after Jan 1,
2017, the incremental activity is subject to MRF
and a C* is calculated based on that activity only
• All revenue from that well bore draws down the
incremental C* from the time of the incremental
activity
24
Re-Entry MRF Wells
25
2020 2024 2017
• Well spud
• C* calculated
• Well will pay
a flat royalty
rate of 5%
under the
MRF regime
• Re-entry to well
occurs
• Well will
receive an
incremental C*
• C* is drawn
down to 0
• Well enters
the Post-C*
rates
Formulas for Re-Entry
C* will be calculated using one of the three
formulas:
1. Lengthened Only
2. Re-fracture Only
3. C*incremental = C*new – C*original
26
C* = ACCI * (1000 * TLLi)
TLLi is the incremental lateral length added to the well
bore.
When to use:
• An existing leg that is lengthened only and occurs
after January 1, 2017
27
Formula – Lengthen Only
Lengthen Only Example
Scenario: A single leg horizontal well is lengthened in 2017
TLLi = New TLL – Prior TLL
= 2183 – 1247
= 936
C*= ACCI * (1000 * TLLi)
= 1.00 * (1000 * 936)
= $936,000
28
Prior to activity Post activity
TVD 1447m 1447m
TLL 1247m 2183m
TPP 947t 947t
C* = ACCI * (1.5 * (0.6 * TVDp * TPPe) + 150,000)
TVDp is the average TVD of all events in the well bore
where proppant is placed
When to use:
• The well is re-fractured only and occurs after January
1, 2017
• Minimum proppant
• Vertical well – 10 tonnes equivalent
• Horizontal well – 50 tonnes equivalent
29
Formula – Re-Fracture Only
Re-Fracture Only Example
Scenario: A multi leg horizontal well is re-fractured in 2017
with resin coated sand.
TVDp = average TVD of all events in the well bore where proppant is
placed
= Average (850 + 1238)
= 1044m
30
2008 2017
Event TVD TLL TPP TVD TLL TPP
00 671m 1110m 312t 671m 1110m 0
02 850m 1121m 451t 850m 1121m 621t
03 1238m 1201m 241t 1238m 1201m 924t
04 1239m 1052m 642t 1239m 1052m 0
Re-Fracture Only Example – Cont’d
TVDp = average TVD of all events in the well bore where proppant
is placed
= Average (850 + 1238)
= 1044m
TPPe = (621 + 924) * 1.5
= 1545 * 1.5
= 2317.5t
C* = ACCI * (1.5 * (0.6 * TVDp * TPPe) + 150,000)
= 1.0 * (1.5 * (0.6 * 1044 * 2317.5) + 150,000)
= $2,327,523
31
Formulas - C* Incremental
This approach will be applied to both ARF and MRF
wells that are:
• any combination of deepening, lengthening and re-
fracturing
• only deepening
Minimum proppant
• Vertical well – 10 tonnes equivalent
• Horizontal well – 50 tonnes equivalent
32
C* Incremental Example
Scenario: A single leg horizontal well that was spud in 2010 has
been re-entered in 2017. Below are the before and after
characteristics of the well.
TPP is sand
33
2010 Attributes 2017 Attributes
Event TVD TLL TPP MD TVD TLL TPP MD
00 671m 1110m 0t 1819m 671m 1110m 0t 1819m
02 850m 1121m 621t 2168m
C* Incremental Example - Cont’dSteps to calculate the C* incremental
1. Calculate the C*original
• Calculate the Y Factor with the 2010 attributes
• Calculate the Proppant Equivalency with the 2010
attributes
• Calculate the C* with the 2010 attributes
2. Calculate the C*new
• Calculate the Y Factor with the 2017 attributes
• Calculate the Proppant Equivalency with the 2017
attributes
• Calculate the C* with the 2017 attributes
3. Calculate the C*incremental
• C*incremental = C*new – C*original
34
C* Incremental Example - Cont’dCalculate the C*original
Step 1 - Calculate the Y Factor with the 2010 attributes
Y = 1.39 – (0.04 * (TMD/TVDa))
= 1.39 – (0.04 * (1819/671))
= 1.28 (1.00)
Step 2 - Calculate the Proppant Equivalency with the 2010 attributes
= 0
Step 3 - Calculate the C* with the 2010 attributes
C* = ACCI * ((1170 * (TVD – 249)) + (Y * 800 * TLL) + (0.6 * TVDa *
TPPe))
= 1.0 * ((1170 * (671– 249)) + (1.00* 800 * 1110) + (0.6 * 671 * 0))
= 1.0 * (493,740 + 888,000 + 0)
= $1,381,740
35
C* Incremental Example - Cont’d
Calculate the C*new
Step 1 - Calculate the Y Factor with the 2017 attributes
Y = 1.39 – (0.04 * (TMD/TVDa))
= 1.39 – (0.04 * (3147/760.5))
= 1.22 (1.00)
Step 2 - Calculate the Proppant Equivalency with the 2017 attributes
= 621 * 1
= 621
Step 3 - Calculate the C* with the 2017 attributes
C* = ACCI * ((1170 * (TVD – 249)) + (Y * 800 * TLL) + (0.6 * TVDa * TPPe))
= 1.0 * ((1170 * (850– 249)) + (1.00* 800 * 2231) + (0.6 * 760.5* 621))
= 1.0 * (703,170 + 1,784,800 + 283,362.30)
= $2,771,332.30
36
C* Incremental Example - Cont’d
Calculate the C*incremental
C*incremental = C*new – C*original
= $2,771,332.30 - $1,381,740
= $1,389,592.30
37
Additional Re-Entry Info
An application to Alberta Energy
([email protected]) is required to
request a C* for the following:
• Acid only fracturing
• Wells with greater than 9 legs
• All re-entries that occur between January 1, 2017 to
April 30, 2017
Applications are to include:
• Letter stating the activity
• Information that validates the activity
38
Revenue Drawdown
• The well revenue will be used to draw down the C*
• Revenue is based on Oil/non-project Oil Sands
production and Gas allocations
• Revenue = ∑ [ (productioni) * (par pricei) ]
• While C* is greater than 0, all products will have a flat
royalty rate of 5%
39
Post-C* Outline
1. Recap of R-C*
2. Revenue calculation
3. Maturity threshold
4. Post-C* royalty rate calculations
Methane & Ethane
Propane
Butanes
Pentanes Plus, Condensate, Conventional Oil, and
Non-Project Oil Sands
40
RecapRevenue - Costs
Alberta Energy determines/calculates:
• C* is the Drilling and Completion Cost Allowance (DCCA)
• R is Revenue - calculated by Alberta Energy:
- Based on conventional oil, natural gas and by-product production
- Revenue = ∑ [ (productioni) * (par pricei) ]
• If R < C*: R% defaults to 5%
• If R ≥ C*: R% is calculated using the post-C* royalty formulas (to
follow)
• Revenue will be amended in open years based on changes in gasallocations and oil production
• Revenue and C* will be calculated by Alberta Energy and a summaryreport will be available on Petrinex
• Sample Report, …
41
Sample Report
42
Revenue• Revenue will be calculated by Alberta Energy for all
MRF wells
• Revenue = ∑ [ (productioni) * (par pricei) ] for all “i”, where “i”
is all production from the well, for all months
• Revenue will adjust to allocation amendments
• Calculations are rolled up to the well/licence level for all
production, including:
43
Conventional oil Wellhead production
Condensate
Natural gas – ISC (methane, ethane, …)
Allocated volumes Natural gas by-products – liquids Mix and Spec
(propane, butanes and pentanes plus)
Sulphur
ExampleRevenue Calculation
Product Wellhead
production
Allocated
volumes
Par Price Calculated
Revenue
Light Oil 100 250.00 25,000.00
Natural Gas (methane, ethane,…)
50 2.10 105.00
Propane Mix 15 155.00 2,325.00
Propane Spec 12 165.00 1,980.00
TOTAL REVENUE 29,410.00
44
Post -C* Royalty Rate
• Apply when R ≥ C*
• Post-C* formula is similar to ARF formulas:
R% = Rp + Rq
Where:
Rp = price component and
Rq = quantity component (reflects the maturity
threshold)
45
Maturity Threshold
• Maturity Threshold is built into the Rq
– Above threshold → no adjustment to Rp
– Below threshold → Rq reduces the royalty rate for
the well
• Maturity Threshold is based on the total production
from the well/licence
– Includes all well events for the well bore
– Based on the sum of conventional oil reported
production and raw natural gas production (well
head)
46
Maturity Threshold• Maturity Threshold is the combined monthly oil wellhead
production and raw gas production from the well
• Gas Equivalent Volumes (GEV) = 345.5 103m3
• Oil Equivalent Volumes (OEV) = 194.0 m3
• Conversion factor of 1.7811 (i.e. 194.0 * 1.7811 = 345.5)
• For example, in the month of January
47
Product Wellhead
Production
Raw Gas
Production
GEV
103m3
OEV
m3
Conventional Oil 125.0 m3 - 222.6 (=125.0 * 1.7811)
125.0
Natural Gas - 90.0 103m3 90.0 50.5 (=90.0 / 1.7811)
TOTAL 312.6 175.5
Post-C* Royalty Rates: Methane and Ethane
• Applies to methane (C1) and ethane (C2)
• ISC, extracted or liquid
• Rq: Use total well gas equivalent production
• Rp: Apply methane and ethane par price(s) (PP)
• R% = Rp + Rq
– Minimum: 5%
– Maximum: 36%
48
49
Post-C* Royalty Rates: Methane and Ethane
Par Price (PP) ($ / GJ) Rp%
PP ≤ $2.40 / GJ 5%
$2.40 / GJ < PP ≤ $3.00 / GJ = [(PP – 2.40) * 0.06000 + 0.05000] * 100
$3.00 / GJ < PP ≤ $6.75 / GJ = [(PP – 3.00) * 0.04250 + 0.08600] * 100
PP > $6.75 / GJ = [(PP – 6.75) * 0.02250 + 0.24538] * 100
Maximum 36%
Quantity (Q)
(103m3 equivalent / month)
Rq%
Q ≥ 345.5 0%
Q < 345.5 [(Q – 345.5) * 0.0004937] * 100
Post- C* Royalty Rates: Propane• Applies to:
– ISC
– Liquids (mix or spec)
• Rq: Use total well oil equivalent
production
• Rp:
– Propane mix PP used for mix
and ISC Rp
– Propane spec PP used for
spec Rp
• R% = Rp + Rq
– Minimum: 5%
– Maximum: 36%50
Mix
PP
Spec
PP
Spec
Rp
Mix
Rp
ISC
Rp
51
Post-C* Royalty Rates: Propane
Par Price (PP) ($ / m3) Rp%
PP ≤ $88.10 / m3 10%
$88.10 / m3 < PP ≤ $143.16 / m3 = [(PP – 88.10) * 0.00202 + 0.10000] * 100
$143.16 / m3 < PP ≤ $253.28 / m3 = [(PP – 143.16) * 0.00111 + 0.21122] * 100
PP > $253.28 / m3 = [(PP – 253.28) * 0.00059 + 0.33347] * 100
Maximum 36%
Quantity (Q)
(m3 equivalent / month)
Rq%
Q ≥ 194.0 0%
Q < 194.0 = [(Q – 194.0) * 0.001350] * 100
Post-C* Royalty Rates: Butanes
52
• Applies to:
– ISC
– Liquids (mix or spec)
• Rq: Use total well oil equivalent
production
• Rp:
– Butanes mix PP used for mix
and ISC Rp
– Butanes spec PP used for
spec Rp
• R% = Rp + Rq
– Minimum: 5%
– Maximum: 36%
Mix
PP
Spec
PP
Spec
Rp
Mix
Rp
ISC
Rp
53
Post-C* Royalty Rates: Butanes
Par Price (PP) ($ / m3) Rp%
PP ≤ $176.19 / m3 10%
$176.19 / m3 < PP ≤ $286.31 / m3 = [(PP – 176.19) * 0.00101 + 0.10000] *100
$286.31 / m3 < PP ≤ $506.55 / m3 = [(PP – 286.31) * 0.00055 + 0.21122] *100
PP > $506.55 / m3 = [(PP – 506.55) * 0.00031 + 0.33235] *100
Maximum 36%
Quantity (Q)
(m3 equivalent / month)
Rq%
Q ≥ 194.0 0%
Q < 194.0 = [(Q – 194.0) * 0.001350] * 100
Post-C* Royalty Rates:
• Conventional Oil, Condensate and Pentanes
Plus
• R% = Rp + Rq
– Minimum: 5%
– Maximum: 40%
54
Post-C* Royalty Rates: Conventional Oil• Applies to light, medium,
heavy and ultra-heavy
production volumes
• Rq: Use total well oil
equivalent production
• Rp:
– Apply the applicable oil
PP to determine the light,
medium, heavy or ultra-
heavy Rp
55
Heavy
Rp
Medium
Rp
Light
Rp
Ultra-
Heavy
Rp
Light
PP
Medium
PP
Heavy
PP
Ultra-
Heavy
PP
Post-C* Royalty Rates: Pentanes Plus & Condensate
56
• Applies to:
– C5+ ISC
– C5+ Liquids (mix or spec)
– Condensate
• Rq: Use total well oil equivalent
production
• Rp:
– C5+ spec PP used for C5+
spec and ISC, and
condensate Rp
– C5+ mix PP used for mix Rp
Mix
PP
Spec
PP
Spec
Rp
Mix
Rp
ISC
Rp
Cond
Rp
57
Post-C* Royalty Rates: Conventional Oil, Condensate and Pentanes Plus
Par Price (PP) ($ / m3) Rp%
PP ≤ $251.70 / m3 10%
$251.70 / m3 < PP ≤ $409.02 / m3 = [(PP – 251.70) * 0.00071 + 0.10000] *100
$409.02 / m3 < PP ≤ $723.64 / m3 = [(PP – 409.02) * 0.00039 + 0.21170] *100
PP > $723.64 / m3 = [(PP – 723.64) * 0.00020 + 0.33440 ] *100
Maximum 40%
Quantity (Q)
(m3 equivalent / month)
Rq%
Q ≥ 194.0 0%
Q < 194.0 = [(Q – 194.0) * 0.001350] * 100
Sulphur Royalty Rate
• No change to the royalty rate calculations under MRF
• Remains same rate as under ARF
- 16.66667%
58
59
ACTUAL DRILLING AND COMPLETION COST REPORTING
Actual Costs Overview
• Actual costs are required so that Alberta Energy can
calculate the Alberta Capital Cost Index (ACCI)
– Used in the C* formulas
• All MRF eligible wells must submit costs
– AFEs for each well
– Actual costs
• Reported costs include
– Required costs
– Voluntary or additional costs
60
Required Costs
Categories:
• Drilling
• Completion
• Re-entry
• Re-completion
61
Drilling Costs (AFE)
Sample Drilling Costs
Included Costs Excluded Costs
• Costs included in the Drilling AFE(s)
provided, including:
• Sampling, logging
• Camp and subsistence,
• Rig costs, drilling labour
• Transportation & hauling
• On-site geology, engineering &
supervision
• Mud, chemicals, water and handling
• Crew travel & lodging
• Fuel and power, heat/steam costs
• Equipment rentals
• Drilling supplies and materials
• Drilling waste management
• Drilling expendables
• Drilling collars, casing, bits,
centralizers
• Safety & inspection
• Costs that are not regularly part of the
Drilling AFE(s), including:
• Permanent surface facilities
• Land bonuses, acquisition
• Ongoing well operating and
maintenance
• Trunk Roads, production haul roads
• Overhead (in excess of acceptable
drilling and JV charges)
• Well license/applications
• Surface lease and survey
• Pipelines
• Above ground facilities (gas plant)
• Costs included in any other category
• Acquisition and exploration
62
Completion / Recompletion Costs (AFE)
Sample Completion / Recompletion Costs
Included Costs Excluded Costs
• Costs included in the Completion/
Recompletion AFE(s) provided, including:
• Tubing, Cementing, Stimulation
• Water including logistics and hauling
• Equipment rentals
• Completion fluid, Proppant
• Wellsite supervision
• Wellhead equipment
• Perforating, service rig, testing,
Downhole tools
• Inspection/safety, In-house
engineering
• Slickline/wireline
• Environmental
• Nitrogen
• Costs that are not regularly part of the
Completion/Recompletion AFE(s),
including:
• Above ground production facilities
• Production related costs
• Costs included under any other
category
Categories:
• Costs related to drilling and completion activities that
are not specifically included in the required costs
• Will be reviewed and evaluated to determine if they
should be part of the three-to-five year recalibration
• Must include detailed description of the nature of the
costs and how it is applicable to the drilling and
completion of the well
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Voluntary / Additional Costs
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Industry Reporting Timelines
AFEs:
• Report costs based on AFEs on a per well basis directly into Petrinex. Costs
may be reported as soon as AFEs are available.
• Electronic copies of the AFEs must be entered into Petrinex before the end
of the month the well commences production to avoid a penalty
Actual costs:
• Supporting transaction details must accompany the reported actual
amounts
- For example wells drilled and completed from January 1 to December
31, 2017
- Actual costs must be submitted by April 30, 2018
- Alberta Energy will determine ACCI and publish it by the end of July
2018 – applicable for 2019
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Industry ReportingAuditing and Penalties
Alberta Energy will conduct appropriate auditing of AFEs
and actual cost submissions
• Will contact operators if needed
Penalties
• Petrinex to provide warning if deadlines are not met
• Alberta Energy will waive penalties for initial 6 months
• Penalties will range from $1,000 - $5,000 per month for
late submissions
Modernized Royalty Framework Strategic
Programs 2017Emerging Resources Program (ERP) and
Enhances Hydrocarbon Recovery Program (EHRP)
• Overview• Program details• Application process
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Emerging Resources Program (ERP) Overview• Panel recommended a strategic program for “high-risk experimental wells”
• Focuses on development of emerging new resources that can be unlocked with
high risk, high cost wells in relatively undeveloped areas
• Promotes innovation and industry experience
• Generates greater long-term royalties and other benefits to Albertans
• Applies to all hydrocarbons
• Program came into effect January 1, 2017
• Applicants select the emerging resource and define a project in the application
• Project must meet all eligibility criteria and must be in the public interest
• Eligible wells in approved projects receive a program specific C*(C*ERP) up todouble original C*
• Non-Project Oil Sands, which are included in a pending ERP application or in anapproved ERP, will not be allowed to form part of an Oil Sands Project
Program Details: ERP Eligibility Criteria• Large resource potential
• Early stage of development
• Strong potential for project area to achieve commerciality
• Net royalty benefit to Albertans
Project Area
• Must be between 18 to 144 sections
• Will only include lands where the leaseholders have secured the Crownmineral rights (freehold land & undisposed excluded)
• The Project Area (PA) sections may or may not be adjacent to one another
• Drilling activity in and near the PA will determine a project’s eligibility andthe project’s total program benefits
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Project Evaluation Boundary
• The Project Evaluation Boundary (PEB) encompasses
the PA plus a buffer zone
• The PEB is established for each project based on set
parameters and may vary with different PA
characteristics
• Existing drilling activity in PEB will determine a project’s
eligibility and the project’s initial program benefits
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Distance from Project Area
Greatest Distance from Nearby
Sections in Project Area
Project Evaluation
Boundary
Project Area
2 sections
4 sections
PEB set at half the greatest
distance between parts of
non-contiguous Project Area;
X = 4/2 or 2
Distance from Project Area
Greatest Distance from Nearby
Sections in Project Area
Project Evaluation
Boundary
Project Area
PEB set at half the greatest
distance between parts of
non-contiguous Project Area;
X = 4/2 or 2
Existing Drilling Activity
Existing Drilling Activity at the time of application impacts
a project’s eligibility and program benefits
• ≤ 10% of total well inventory drilled within the PEB
- Include wells that penetrated the target formation
• ≤ 15% of total well inventory drilled within the PA
- Include wells producing from the target formation
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New Drilling ActivityNew drilling activity within the PA receives program benefits• Up to the first 15% of the total well inventory in the PA may be eligible toreceive benefits
- Includes new wells producing from the target formation that are drilledwithin the project benefit period
C* Multiplier
• C*ERP will be calculated using the well’s C* times a C*
Multiplier
• The C* Multiplier ranges from 1.5 to 2.0
• The C* Multiplier for an eligible well depends on existing
activity within the PEB at the time of application and
when the well is drilled
• The C* Multiplier available for future eligible wells
declines over time for each project
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C*ERP For Approved Projects
• C*ERP will be provided to eligible wells from an approved
project once the wells are on production
• C*ERP includes both the C* a well receives under the
MRF, and the additional C*ERP provided by the Program
• C*ERP for eligible wells in a project are pooled for
purposes of the Program
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C* Multiplier Benefit Schedule
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Column 1
Project Activity Level
Column 2 Project Benefit Period (Years)
Column 3
Elapsed Time (Years)
Column 4
C* Multiplier
less than 5% 10
0-4 2.00
5-8 1.75
9-10 1.50
greater than or equal to 5% and less than 6% 9
0-3 2.00
4-7 1.75
8-9 1.50
greater than or equal to 6% and less than 7% 8
0-2 2.00
3-6 1.75
7-8 1.50
greater than or equal to 7% and less than 8% 7
0-1 2.00
2-5 1.75
6-7 1.50
greater than or equal to 8% and less than 9% 6
0-4 1.75
5-6 1.50
greater than or equal to 9% and less than or equal to 10% 5
0-3 1.75
4-5 1.50
greater than 10% 0 N/A N/A
Pooling of C*ERP
• C*ERP for eligible wells in a project are pooled for
purposes of the Program
• All eligible project wells contribute to the drawdown of
the pooled C*ERP
• The pooled C*ERP will be available to those eligible wells
for up to 5 years after the approved benefit period ends
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Application Process• Applications will only be accepted after December 31,2016• Applications will not undergo a technical evaluationprior to all required application materials being received byAlberta Energy
Application Checklist
Detailed application forms will be available
Applicants will be required to provide (including but not
limited to):
• Detailed description of the project including the PA
and PEB
• Resource estimates
• Production forecasts
• Project economics
• List of all existing wells in the emerging target
formation within the PEB
81
Application Review Timeline
82
Enhanced Hydrocarbon Recovery Program (EHRP) Overview• Panel Recommendation: A strategic program to promote enhanced recovery projects in legacy fields
• Aligns with the principles of the MRF
• Applies to all hydrocarbons
• Program encourages incremental hydrocarbon production through recognized injection methods
• Generates incremental royalty revenue for Albertans
• Replaces existing Enhanced Oil Recovery Program (EORP)
83
Comparison of EORP and EHRP
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EORP:
• Applies to oil wells only
• Eligibility restricted to
select tertiary enhanced
recovery methods
• Applies a maximum 5%
royalty rate to wells for a
prescribed benefit period
EHRP:
• Applies to all
hydrocarbons (crude oil,
natural gas and liquids)
• Eligibility expanded to
include additional
enhanced recovery
methods
• Applies a flat 5% royalty
rate to wells for a
prescribed benefit period
EHRP Program ApplicationApplication based program. Applicant will supply:
• Maps of scheme area and ownership
• Maps of facility and pipeline locations
• AER technical approval (can be forwarded when approved)
• Engineering Evaluation Report
• Production and costs for base scheme and enhanced
scheme (forecast)
Applications will only be accepted after December 31, 2016
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EHRP Program Description
• Two eligible stages of recovery
– Secondary recovery
– Tertiary recovery
• Wells in an approved enhanced recovery scheme will
pay a flat 5% royalty rate for a prescribed benefit period
• After the prescribed benefit period ends, wells in the
scheme will pay post-C* royalty rates under the MRF
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Scheme Definitions for Program
• Secondary Recovery: enhanced recovery of
hydrocarbons by water flooding, polymer flooding, gas
cycling, gas flooding or other approved methods
• Tertiary Recovery: enhanced recovery of hydrocarbons
by immiscible flooding, miscible flooding, solvent
flooding, chemical flooding or other approved methods
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EHRP Eligibility Criteria
• Receive technical approval of the scheme through an
application submitted to the AER on or after October 23, 2016
• The scheme is an enhanced recovery scheme that meets the
definition of either secondary or tertiary recovery
• Produces more hydrocarbons from the pool than could beproduced under the base recovery scheme for that pool
• Costs are significantly greater than operating the baserecovery scheme
• Provides a net royalty benefit to the Crown over the life of thescheme as determined by a technical/economic review
88
Schemes Not Eligible for EHRP
Schemes are not eligible to apply to the EHRP if:
• The operator applied to the AER for technical approval
prior to October 23, 2016
• The scheme is an existing scheme amended through the
AER due to reasons other than changing injection
material/recovery method
• For new water flood or gas cycling/flooding schemes, the
scheme is located in a pool or part of a pool that has
previously been water flooded, gas cycled or gas flooded
89
EHRP Benefit Period
• EHRP will provide benefits (flat 5% royalty rate) for a prescribed period for
approved schemes:
– Secondary recovery: the benefit period will be determined on a case by
case basis
– Tertiary recovery: benefit period will be based on the scheme’s tertiary
recovery factor (T-factor) as determined by Alberta Energy, and a
benefit schedule
Benefit Period Start Date – Secondary Recovery: The benefit period start date will be determined on a
case by case basis in conjunction with Alberta Energy and the operator
– Tertiary Recovery: After material is first injected, operators will have up to 36 months to begin their benefit period
90
ARF Wells in EHRP Schemes
• Wells drilled before 2017 that become part of an EHRP
scheme will be fully transitioned to the MRF:
– Will pay a flat 5% royalty rate while the scheme is
receiving benefits under EHRP
– After the benefit period ends, wells will pay post-C*
royalty rates under MRF
• Non-Project Oil Sands wells, which are included in a
pending EHRP scheme application or in an approved
EHRP scheme, will not be allowed to form part of an Oil
Sands Project
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EORP Moving Forward
• Applications for EORP will be accepted until December
31, 2016
• EORP will continue for up to 10 years for approved
schemes
• EORP approved schemes with any benefit period
remaining by December 31, 2026 will not transition to
EHRP and remaining benefits will expire
– These wells will pay MRF royalty rates after 2026
92
New Wells in EORP Schemes• Any new producing wells drilled into an EORP scheme
on or after January 1, 2017 will receive a C*
• New wells will pay a flat 5% royalty rate until revenue
equals the C* or the benefit period for the scheme ends,
whichever occurs later
– The wells will then pay post-C* royalty rates under the
MRF
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EORP Scheme Amendments
• As of January 1, 2017, amendments to existing EORP
schemes may submit an application for EHRP if:
– The amendment involves a change in injection material or
recovery technique; and/or
– An expansion outside the scheme area that includes anew injection pattern (i.e. at least one producer and one
injector well)
• Expansions outside of an existing EORP scheme that includea new injection pattern will be treated as a separate schemeand administered under EHRP
• Amended EORP schemes that meet the criteria to apply forEHRP must still meet all the eligibility criteria that applies toapplications for new schemes
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Contact Information
• All MRF related questions , please send
• ERP and EHRP related questions,
please send to
• General technical questions can be sentto [email protected]
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