Modernized Royalty Framework (MRF) 2017 1 D isclaimer This - - PowerPoint PPT Presentation

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.

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Outline

1. 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

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MRF Overview - Historical Context

Royalty 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)

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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

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What is C* ?

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C*= ACCI * ((1170 * (TVD - 249))

+ (3120 * (TVD - 2000)) + (Y * 800 * TLL) + (0.6 * TVDa * TPPe))

+ C* Outline

• 1. Definitions
• 2. Formulas
• 3. 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 industry

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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*

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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

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Definition of Terms

Total Lateral Length (TLL) - the total lateral length of a well in metres

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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

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Definition of Terms

Proppant Equivalency Table Equivalency Factor

1 1.5 2.5

Type of Completion

Sand (tonnes) 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

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Proppant Equivalency Table Examples

Equivalency Factor Volume TPPe 1 700 tonnes 700 1.5 700 tonnes 1050 Type of Completion Sand (tonnes) 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 0.24

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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

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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

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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) 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 TVD

C*= 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 TVD

C*= 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-in wells

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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 Factor

Y = 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

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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 Factor

Y = 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

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Re-Entry

For 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

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Re-Entry ARF Wells

• When an ARF 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

• The whole well bore will switch from ARF to MRF until the incremental

C* is drawn down completely

• All revenue from that well bore draws down the incremental C* from the

time of the incremental activity

• Once the C* is completely drawn down, the well bore reverts back to

ARF

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2017 2017 2024 2024 2010 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

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Re-Entry MRF Wells

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2020 2020 2024 2024 2017 2017

• Well spud
• C* calculated
• Well will pay

a flat royalty rate of 5% under the MRF regime

• Re-entry to well
• ccurs
• 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

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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

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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

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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

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Formula – Re-Fracture Only

Re-Fracture Only Example

Scenario: A multi leg horizontal well is re-fractured in 2017 with coated sand.

TVDp = average TVD of all events in the well bore where proppant is placed = Average (850 + 1238) = 1044m

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2008 2017 Event TVD TLL TPP TVD TLL TPP 00 671m 1110m 312t 671m 1110m 02 850m 1121m 451t 850m 1121m 621t 03 1238m 1201m 241t 1238m 1201m 924t 04 1239m 1052m 642t 1239m 1052m

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

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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

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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

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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’d

Steps 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

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C* Incremental Example - Cont’d

Calculate 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

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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

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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

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Additional Re-Entry Info

An application to Alberta Energy (Energy.MRFInquiries@gov.ab.ca) 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

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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%

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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

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Recap Revenue - 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 gas

allocations and oil production

• Revenue and C* will be calculated by Alberta Energy and a summary

report will be available on Petrinex

• Sample Report, …

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Sample Report

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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:

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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

Example Revenue 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

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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)

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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)

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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

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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%

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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%

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Mix PP Spec PP Spec Rp Mix Rp ISC Rp

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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

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• 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

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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%

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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

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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

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• 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

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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%

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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

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Required Costs

Categories:

• Drilling
• Completion
• Re-entry
• Re-completion

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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

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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
• f 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 Reporting Auditing 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 2017

Emerging 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 to

double original C*

• Non-Project Oil Sands, which are included in a pending ERP application or in an

approved 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 Crown

mineral 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 and

the 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 Activity

New drilling activity within the PA receives program benefits

• Up to the first 15% of the total well inventory in the PA may be eligible to

receive benefits

• Includes new wells producing from the target formation that are drilled

within 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

79 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% 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 evaluation

prior to all required application materials being received by Alberta 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

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Application Review Timeline

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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)

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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 Application

Application 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 be

produced under the base recovery scheme for that pool

• Costs are significantly greater than operating the base

recovery scheme

• Provides a net royalty benefit to the Crown over the life of the

scheme as determined by a technical/economic review

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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

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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

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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

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New Wells in EORP Schemes

• Any new producing wells drilled into an EORP scheme
• n 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 a new injection pattern (i.e. at least one producer and one injector well)

• Expansions outside of an existing EORP scheme that include

a new injection pattern will be treated as a separate scheme and administered under EHRP

• Amended EORP schemes that meet the criteria to apply for

EHRP must still meet all the eligibility criteria that applies to applications for new schemes

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Contact Information

• All MRF related questions , please send

to Energy.MRFInquiries@gov.ab.ca

• ERP and EHRP related questions,

please send to MRFPrograms@gov.ab.ca

• General technical questions can be sent

to oil.gas.royalty@gov.ab.ca

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