Modernized Royalty Framework (MRF) - Alberta · December 31, 2016 – Benefits continue until they...

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)

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)

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)

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 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

(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

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

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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 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

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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

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

to Energy.MRFInquiries@gov.ab.ca

• ERP and EHRP related questions,

please send to

MRFPrograms@gov.ab.ca

• General technical questions can be sentto oil.gas.royalty@gov.ab.ca

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