New
N
Royalty
R
lt Formula
F
l
October 2008
DISCLAIMER
 THIS PRESENTATION
IS FOR INFORMATIONAL PURPOSES ONLY,
PENDING APPROVAL OF THE NATURAL GAS ROYALTY
REGULATIONS 2009 AND THE NATURAL GAS DEEP DRILLING
REGULATIONS.

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
1.
1
2.
3.
4.
5.
6.
7.
Overview
Royalty Formula
S l ti
Solution
Gas
G
Field Condensate
WEARR
Prices
Royalty Valuation
3




NRF implementation
i
l
t ti
- January
J
2009 production
d ti
period
i d (M
(March
h
2009 calendar month)
Methane ISC, Ethane and Extracted Ethane:
◦ R% = Price Component (rp%) + Quantity Component (rq%)
◦ Minimum:
5%
◦ Maximum:
50%.
The
h following
f ll
have
h
fixed
f d royalties,
l
whether
h h extracted
d or left
l f in
the gas stream as an ISC:
◦ Propane:
30%.
◦ Butanes:
30%.
◦ Pentanes Plus: 40%.
Sulphur royalty rate:16.66667% (unchanged)
5
A.
B.
Price Component
Quantity
y Component
p


New royalty formula applies to:
◦ Methane ISC,
◦ Ethane
Eth
ISC and
d
◦ Extracted Ethane
The determination of the royalty rate for these
products is based on the new royalty formula
◦ The sum of the price and quantity components
◦ R% = rp% + rq%
◦ Minimum:
5%
50%
50%.
◦ Maximum:
7

The price component of the new royalty formula
royalty rate is determined by the monthly
methane or ethane par price (PP)
Price ($/GJ)
PP ≤ 7.00
00
7.00 < PP ≤ 11.00
PP > 11.00
Maximum
Minimum
rp
( – 4.50)
(PP
4 0) * 00.0450
04 0
(PP – 7.00) * 0.0300 + 0.1125
(PP – 11.00) * 0.0100 + 0.2325
30%
Can be negative (-20.25% if PP=0)
9


PP are:
◦ determined by the department,
◦ a provincial
i i l weighted
i ht d price,
i
and
d
◦ published in Information Letter (IL) for each
production month.
p
PP has not changed under NRF
10

If the PP, for methane is $6.60/GJ:
Price ($/GJ)
rp
PP ≤ 7.00
((PP – 4.50)) * 0.0450
7.00 < PP ≤ 11.00
(PP – 7.00) * 0.0300 + 0.1125
PP > 11.00
(PP – 11.00) * 0.0100 + 0.2325
rp = (PP – 4.50) * 0.0450
= (6.60 – 4.50) * 0.0450
= 9.45%
11

If the PP, for ethane is $4.00/GJ:
Price ($/GJ)
rp
PP ≤ 7.00
(PP – 4.50) * 0.0450
7.00 < PP ≤ 11.00
(PP – 7.00) * 0.0300 + 0.1125
PP > 11
11.00
00
(PP – 11.00)
11 00) * 00.0100
0100 + 00.2325
2325
rp = (PP – 4.50) * 0.0450
= (4.00 – 4.50) * 0.0450
= -2.25%
12

If the PP, for methane is $8.50/GJ:
Price ($/GJ)
rp
PP ≤ 7.00
(PP – 4.50) * 0.0450
7.00 < PP ≤ 11.00
(PP – 7.00) * 0.0300 + 0.1125
PP > 11
11.00
00
(PP – 11.00)
11 00) * 00.0100
0100 + 0.2325
0 2325
rp = (PP – 7.00) * 0.0300 + 0.1125
= (8.50 – 7.00) * 0.0300 + 0.1125
= 15.75%
13

If the PP,
PP for ethane is $18.25/GJ:
$18 25/GJ:
Price ($/GJ)
rp
PP ≤ 7.00
7 00
(PP – 4.50)
4 50) * 00.0450
0450
7.00 < PP ≤ 11.00
(PP – 7.00) * 0.0300 + 0.1125
PP > 11.00
(PP – 11.00) * 0.0100 + 0.2325
rp = (PP – 11.00) * 0.0100 + 0.2325
= (18.25–
( 8 5 11.00)
00) * 0.0100
0 0 00 + 0.2325
0 3 5
= 30.50%
Exceeds the cap => rp = 30%
14

Determination
D
i
i
off the
h rq is
i based
b
d upon:
◦ average daily production (ADP)
 acid gas content (AGF)
◦ depth (DF)
Quantity (103m3/d)
rq
ADP≤ (6 * DF)
[ADP – (4 * DF)] * (0.0500/DF)
(6 * DF) < ADP ≤ (11* DF)
[ADP – (6 * DF)] * (0.0300/DF) + 0.1000
ADP > (11* DF)
[ADP – (11 * DF)] * (0.0100/DF) + 0.2500
Maximum
30%
Minimum
g
Can be negative
16


Under the current royalty regime the ADP is
used to determine the Low Productivity Well
Allowance (LPWA)
LPWA will be discontinued January 2009
production period
17


Definition: The ADP for a well event is the total raw
gas production (103m3) for the month divided by
the total hours of production in that month
multiplied by 24.
ADP has not changed under NRF.
total raw gas production
ADP 
 24
total hours of production
18


A well event reports the following for production
month, January 2009:
◦ Raw gas production:
233 6 103m3
233.6
◦ Production hours:
512.0 hours
The ADP is:
◦ ADP = (233.6 / 512) * 24
0 9 10
03m3/day
d
◦ ADP = 10.95
19



AGF: adjusts the ADP of a well event.
event
Applies to well events with a combined
concentration of H2S and CO2 of >3% and ≤25%.
The AGF is determined based on the following
formula:
◦ AGF = [1.03 – (H2S% + CO2%)]
20
If CO2  H2S is
 3%  AGF  1.00
1 00
 3% and  25%  AGF 1.03- CO2 %  H2S%
 25%  AGF  0.78
0 78

The ADP is
Th
i adjusted
dj t d by
b multiplying
lti l i
th
the ADP by
b th
the
AGF, that is:
◦ Adjusted
j
ADP = ADP * AGF
21





A well event has the following acid gas content:
H2S=4% and CO2=5%
AGF
G = [1.03
[ 03 – (H
( 2S%+CO
S% CO2%)] = [[1.03
03 – (0.04+0.05)]
(0 0 0 0 )]
= [1.03 – 0.09] = 0.94
Using previous example ADP =10.95 103m3/day
Then the Adjusted ADP = ADP × AGF
= 10.95 × 0.94 =10.293 103m3/day
22



Required for all well events
Used in the determination of the rq
Adjusts the rq formula for MD >2,000m
23


The calculation of the DF is based on the
measured depth (MD) according to the records of
the ERCB.
ERCB
Definition:
The MD is the longest
g
distance along
g the bore of
the well from the kelly bushing to the base of the
producing zone (gross completion interval (GCI)),
according to the records of the ERCB
24


Information on the MD, of a well event,
can be found on the PRA in the
‘Infrastructure’ section
As p
per the following
g screen shots
Enter the “Query Well” for MD information on a well event
1. Enter
Licence
Number
2. Clicking “Go”
will populate
th window
the
i d
below
3. Highlight well event
4. Click “Details” to receive information on well event Number
 1 or more well events with no drains
◦ Calculate MD for each well event
◦ MD is the longest distance along the bore of the well from the
kelly bushing to the bottom of the GCI.
 1 producing well event with 1 or more drains
MD is the sum of:
g of the producing
p
g well event from the kelly
y bushing
g of
◦ Length
the well to the bottom of the GCI, and
◦ Sum of the lengths of all the drains contributing to the
producing well event’s production, where the length of a drain
is between the last kick-off point of the drain (leg or well bore)
and the total depth of each corresponding drain
28


Use the MD to determine the DF
The DF for a well event is determined as follows:
 MD 
DF  

 2000 
2
29

A well event without a reported MD then the DF
defaults to 1
 2,000 m then the DF  1.00
If the MD is
 MD 
 2,000m and  4,000m then the DF  

 2000 
 4 ,000 m then the DF  4.00
2
30




Changes to the MD are to be reported by
Industry through the PRA
All MD amendments are subject to review by the
ERCB and department
All changes will be applied on a go forward basis
Retroactive changes: written request must be
submitted to GRCU
31





For a well with only 1
producing well event
MD = 2,600m
DF = (2,600/2,000)2
= (1.30)2
= 1.69
32








A well with 2 producing well events
Each well event will have its own DF
/ event:
/0
MD = 3,600 m (length ‘B’)
DF = (3,600/2,000)2 = 1.802 = 3.24
/2 event:
MD = 3,800 m (length ‘C’)
DF = (3,800/2,000)
(3 800/2 000)2 = 1.90
1 902 = 3.61
3 61
33




For a well that has 6
well events,
/0 well event is
/
producing
Other 5 well events are
reported as drains
Then the MD
…
34
Well
W ll
Event
/0
/2
/3
/4
/5
/6
MD
Status
St t
Producing
Drain
Drain
Drain
Drain
Drain




Total
T t l Depth
D th
(1)
Kickoff
Ki
k ff Point
P i t
(2)
Length
L
th off leg
l
[for drains = (1) – (2)]
Identifier
Id tifi
(see chart)
2,600
2,500
3,000
2,700
2,900
,
1,600
1,500
2,000
1,800
2,400
1,200
,
2,600
1,000
1,000
900
500
400
6,400
A
E
F
D
C
B
Total MD = 6,400m
DF = (6,400/2,000)2 = (3.20)2 = 10.24,
The DF is capped at 4.00
DF = 4.00
35





If any of the well events is abandoned then its leg length is
not included in the MD
Using
g the previous
p
example
p information
The /3 well event is abandoned then its 1,000m, length (F),
is not included in the MD
◦ MD = A + B + C + D + E
◦ =2,600 + 400 + 500 + 900 + 1,000 = 5,400
DF = (5,400/2,000)2 = 2.72 = 7.29
The DF is capped at 4.00
36


Having reviewed each of the following:
◦ ADP,
◦ AGF, and
◦ DF
We can determine the rq
Quantity (103m3/d)
ADP≤ (6 * DF)
(6 * DF) < ADP ≤ (11* DF)
ADP > (11* DF)
Maximum
Minimum
rq
[ADP – (4 * DF)] * (0.0500/DF)
[ADP – (6 * DF)] * (0.0300/DF) + 0.1000
[ADP – (11 * DF)] * (0.0100/DF) + 0.2500
30%
Can be negative
37
MD is ≤ 2,000m => DF = 1.00
Then the rq equation are:
Quantity (103m3/d)
rq
ADP ≤ 6
[ADP – 4] * (0
(0.0500)
0500)
6 < ADP ≤ 11
[ADP – 6] * (0.0300) + 0.1000
ADP > 11
[ADP – 11] * (0.0100) + 0.2500
Maximum
Minimum
30%
Can be negative
38



If the
th MD for
f a well
ll eventt is
i >2,000m
2 000 then
th the
th DF
> 1.00.
If the MD =3,200m, then the DF = 2.56
The rq calculation table is adjusted as follows:
Quantity
Q
i (103m3/d)
ADP≤ (6*2.56)
(6*2.56) < ADP ≤ (11*2.56)
ADP > (11*2
56)
(11*2.56)
Maximum
Minimum
rq
[ADP – (4*2.56)] * (0.0500/2.56)
[ADP – (6*2.56)] * (0.0300/2.56) + 0.1000
[ADP – (11*2
56)] * (0
0100/2 56) + 00.2500
2500
(11*2.56)]
(0.0100/2.56)
30%
Can be negative
39

Adjusting
Adj ti
each
h off the
th equations
ti
in
i the
th table
t bl for
f
the DF = 2.56, results in:
Quantity (103m3/d)
rq
ADP≤ 15.36
15 36 < ADP ≤ 28.16
15.36
28 16
[ADP – 10.24] * (0.01953)
[ADP – 15.36]
15 36] * (0
(0.01172)
01172) + 00.1000
1000
ADP > 28.16
[ADP – 28.16] * (0.00391) + 0.2500
Maximum
30%
Minimum
Can be negative
40
41



A well
ll eventt reports
t the
th
following:
CO2 content: 1.00%
H2S content: 0.05%
0 05%

Raw gas production: 112 103m3
Hours on production: 744.0
744 0 hrs

MD of the well event:1,929m


AGF = CO2 + H2S
= 1.00% + 0.05% = 1.05%,
AGF is ≤ 3% => ADP is not adjusted

ADP=(112/744)*24= 3.6129 103m3/d

DF = 1.00, since MD ≤ 2,000m


42





Since
Si
the
h DF = 1 the
h rq% is
i based
b
d the
h table
bl below
b l
ADP = 3.6129 103m3/day => use first equation
Quantity (103m3/d)
rq
ADP≤ 6
[ADP – 4] * (0.0500)
6 < ADP ≤ 11
[[ADP – 6]] * ((0.0300)) + 0.1000
ADP > 11
[ADP – 11] * (0.0100) + 0.2500
rq = [ADP–4]*(0
[ADP–4] (0.0500)
0500) = [3
[3.6129–4]
6129–4]*(0
(0.0500)
0500) = -0
-0.019355
019355
rq% = -1.9355%
Applies to both methane and ethane
43



For
F a well
ll eventt that
th t reports
t the
th
following:
CO2 content: 1.00%
H2S content: 0.05%
0 05%

Raw gas production: 490.0 103m3
Hours on production: 600.0
600 0 hr

MD of the well event: 1,929m






AGF = CO2 + H2S
= 1.00% + 0.05% = 1.05%,
AGF is ≤ 3% the ADP is not adjusted.
ADP = (490/600)*24 = 19.6
103m3/day
DF = 1.00, since MD ≤ 2,000m
44







Since the DF=1 the rq is based on the unadjusted table
ADP = 19.6 103m3/day therefore:
Quantity (103m3/d)
rq
ADP≤ 6
[ADP – 4] * (0.0500)
6 < ADP ≤ 11
[ADP – 6] * (0.0300)
(
) + 0.1000
ADP > 11
[ADP – 11] * (0.0100) + 0.2500
rq = [ADP
[ADP–11]*(0
11] (0.0100)+0.2500
0100)+0 2500
= [19.6 – 11]*(0.0100) + 0.2500
= 0.3360
The rq is capped at 30%
Applied to both methane and ethane
45
For a well event that reports the
following:
CO2 content: 0.95%
H2S content: 1.50%
1 50%



Raw gas production: 490.0 103m3
H
Hours
on production:
d
i
600
600.0hr
0h

MD of the well event: 2,900m







AGF = CO2 + H2S
= 0.95% + 1.50% = 2.45%
AGF is ≤ 3% the ADP is not
adjusted
adjusted.
ADP = (490/600)*24 = 19.6
103m3/day
DF = (2,900/2,000)2 = (1.45)2 =
2.1025
46





DF = 2.1025, this adjusts the rq table as follows:
With the ADP = 19.6 103m3/day therefore
Quantity (103m3/d)
rq
ADP≤ 12.615
[ADP – 8.41] * (0.02378)
12.615 < ADP ≤ 23.1275
[ADP – 12.6150] * (0.01427) + 0.1000
ADP > 23.1275
[ADP – 23.1275] * (0.00476) + 0.2500
rq = [ADP – 12.6150] * (0.01427) + 0.1000
= [19
6 – 12
6150] * (0
01427) + 0
1000
[19.6
12.6150]
(0.01427)
0.1000
rq% = 19.968%, is applied to both methane and ethane
47





For
F a well
ll eventt that
th t reports
t the
th
following:
CO2 content: 7.00%
H2S content: 8.00%
8 00%
Raw gas production: 490.0 103m3
Hours on production: 600 hr







MD of the well event: 2,900m

AGF = [1.03–(H
[1 03 (H2S%+CO
S% CO2%)]
= [1.03–(0.08+0.07)]
= [1.03–0.15] = 0.88
ADP = (490/600)*24 = 19.6
103m3/d
Adjusted ADP = ADP*AGF
=19.60*0.88 = 17.248 103m3/day
DF = (2,900/2,000)2 = (1.45)2 =
2.1025
48





DF = 2.1025, this adjusts the table as follows:
With the ADP = 17.248 103m3/day therefore
Quantity (103m3/d)
ADP≤ 12.615
rq
[ADP – 8.41] * (0.02378)
12 615 < ADP ≤ 23.1275
12.615
23 1275
[ADP – 12.6150]
12 6150] * (0
(0.01427)
01427) + 0.1000
0 1000
ADP > 23.1275
[ADP – 23.1275] * (0.00476) + 0.2500
rq = [ADP
[
– 12.6150]
12 61 0] * (0
(0.01427)
01 2 ) + 0
0.1000
1000
= [17.248 – 12.6150] * (0.01427) + 0.1000
rq% = 16.611%, is applied to both methane and
ethane
49


Applies to both methane and ethane (ISC and
extracted)
For a well event the total royalty rate is the sum
of the price and quantity component
=> R% = rp% + rq%.
50
Calculation of rp%:
 If the PP is as follows:
 Methane ISC: $6.60/GJ
 Ethane
Eh
ISC:
ISC
$4 00/GJ
$4.00/GJ



Then rp as
previously
follows:
rp methane%
rp ethane%
calculated
are as
= 9.45%
= -2.25%
Calculation of rq%:
 For a well event with:
 Raw gas production:
 Hours
H
on production:
d
i
 MD of the well event:
 CO2 content:
 H2S content:


112 103m3
744 h
hrs
1,929m
1.00%
0.05%
Then
e rq as calculated
ca cu ated previously
p e ous y
-1.9355%
51
R% for methane:
 Rmethane% = rp% + rq% = 9.45% + (-1.9355%) = 7.5145%
R% for
f ethane:
h
 Rethane% = rp% + rq% = (-2.25%) + (-1.9355%) = -4.1855%
 Defaults to 5%, the minimum R%
Remaining ISCs are charged
 Propane
opa e ISC:
SC
 Butanes ISC:
 Pentanes Plus ISC:
the following fixed rates:
30%
30%
40%
52


For royalty purposes (Definition):
Solution gas is the gaseous component found
in conventional crude oil or bitumen that is
separated from the crude oil or bitumen after
recovery from a well event
Solution gas has and will continue to be treated
the same as natural gas
54

ADP for solution gas will be based upon the well
event total production of the:
◦
Solution gas
gas, and
◦
Gas equivalent energy content of conventional
oil or bitumen
◦

(conversion factor from oil or bitumen into gas equivalent
energy is 1.0686 103m3 of natural gas per m3).
l calculation
l l
h previous section
Royalty
- as per the
55
Calculation of rp%:
 If the PP is as follows:
 Methane ISC: $6.60/GJ
 Ethane ISC: $4.00/GJ



Then rp as calculated
previously are as follows:
rp methane%
= 9.45%
rp ethane%
= -2.25%
Given the following for the well event:
 Raw gas production:
112 103m3
 Oil production:
97.60 m3
 Hours on production:
744 hrs
 MD:
1,929m
 CO2 content:
1.00%
 H2S content:
0.05%

AGF: CO2 + H2S = 1.00% + 0.05% = 1.05%,
≤3% => ADP is not adjusted

DF = 1.00, Since MD ≤ 2,000m

56
Conversion of Oil Volumes to Energy Adjusted Gas
Volumes:
 = 97.60 m3 * 1.0686 = 104.295 103m3


Total monthly production for well event is the sum of
the converted oil volume and the gas volume:
= 104.295
104 295 103m3 + 112 103m3 = 216.295
216 295 103m3
ADP :
 = (216.295/744)*24
 = 6.977 103m3/day
57





DF = 1
1, use the unadjusted rq table below
below.
With ADP = 6.977 103m3/day use 2nd equation:
Quantity (103m3/d)
rq
ADP≤ 6
[ADP – 4] * (0.0500)
6 < ADP ≤ 11
[ADP – 6] * (0.0300)
(0 0300) + 0.1000
0 1000
ADP > 11
[ADP – 11] * (0.0100) + 0.2500
rq = [ADP – 6] * (0
(0.0300)
0300) + 0
0.1000
1000
= [6.977 – 6] * (0.0300) + 0.1000
= 12.931%,, applied
pp
to both methane and ethane
58
R% for methane:
 Rmethane% = rp% + rq% = 9
9.45%+12.931%
45%+12 931% = 22
22.381%
381%
R% for ethane:
 Rethane% = rp% + rq% = -2.25%+12.931% = 10.681%
Remaining ISCs are charged the following fixed rates:
 Propane ISC:
30%
 Butanes ISC:
30%
 Pentanes Plus ISC:
40%
59


For royalty purposes (Definition):
Field condensate is "products obtained from
natural gas or solution gas before they are
delivered to a gathering system". Typically,
field condensate is separated from gas in the
field and sold or otherwise disposed of
without further processing before entering a
gas gathering system.
The determination of royalties is based on the
conventional oil formula
61
R% = rp% + rq%
Minimum:
Maximum:
0%
50%
Where:

rp: based on the PP of pentanes plus

rq: based on total monthly production of:
◦
Field condensate and
◦
Field condensate equivalent energy content of
th
the gas

(conversion factor from gas into field condensate equivalent
volume is 0.78783 103m3 of natural gas per m3).
62

The rp of the conventional oil royalty formula is
determined by the pentanes plus PP as per the
following table:
Price ($/m3)
rp
PP ≤ 250
250.00
00
(PP – 190.00)
190 00) * 00.0006
0006
250.00 < PP ≤ 400.00
(PP – 250.00) * 0.0010 + 0.0360
PP > 400.00
(PP – 400.00) * 0.0005 + 0.1860
Maximum
35%
Minimum
Can be negative
63


Pentanes Plus PP is:
◦ determined by the department,
◦ a provincial
i i l weighted
i ht d price,
i
and
d
◦ published in Information Letter (IL) for each
production month.
p
PP has not changed under NRF
64

If the
h PP for
f pentanes plus
l is
i $150.00/m
$150 00/ 3
Price (($/m3)
rp
PP ≤ 250.00
(PP – 190.00) * 0.0006
250.00 < PP ≤ 400.00
(PP – 250.00) * 0.0010 + 0.0360
PP > 400
400.00
00
(PP – 400.00)
400 00) * 0.0005
0 0005 + 0.1860
0 1860
rp = (PP – 190.00) * 0.0006
= (150
(150.00
00 – 190
190.00)
00) * 0
0.0006
0006
= -2.40%
65

If the
h PP,
PP for
f pentanes plus
l is
i $225.00/m
$225 00/ 3
Price (($/m3)
rp
PP ≤ 250.00
(PP – 190.00) * 0.0006
250.00 < PP ≤ 400.00
(PP – 250.00) * 0.0010 + 0.0360
PP > 400
400.00
00
(PP – 400.00)
400 00) * 0.0005
0 0005 + 0.1860
0 1860
rp = (PP – 190.00) * 0.0006
= (225
(225.00
00 – 190
190.00)
00) * 0
0.0006
0006
= 2.10%.
66

If the PP,
PP for pentanes plus is $360.00/m
$360 00/m3
Price ($/m3)
rp
PP ≤ 250.00
(PP – 190.00) * 0.0006
250.00 < PP ≤ 400.00
(PP – 250.00) * 0.0010 + 0.0360
PP > 400.00
(PP – 400.00) * 0.0005 + 0.1860
rp = (PP – 250.00) * 0.0010 + 0.0360
= (360
(360.00
00 – 250
250.00)
00) * 0
0.0010
0010 + 0
0.0360
0360
= 14.60%.
67

If the PP,
PP for pentanes plus is $945.00/m
$945 00/m3
Price ($/m3)
rp
PP ≤ 250.00
(PP – 190.00) * 0.0006
250.00 < PP ≤ 400.00
(PP – 250.00) * 0.0010 + 0.0360
PP > 400.00
(PP – 400.00) * 0.0005 + 0.1860
rp = (PP – 400.00) * 0.0005 + 0.1860
= (945
(945.00
00 – 400
400.00)
00) * 0
0.0005
0005 + 0
0.1860
1860
= 45.85%
Exceeds the cap => rp = 35%
68

Determination of the rq is based upon:
◦ The total monthly production (Q) of the well event
event, which is the sum of:
◦ The field condensate (report as a liquid in m3), and
◦ Field condensate equivalent energy content of the gas, that is, the raw
gas production (report as a gas in 103m3) converted to the field
condensate equivalent volume
(conversion factor from gas into field condensate equivalent volume is 0.78783)
Quantity (m3/month)
Q ≤ 106.4
106.4 < Q ≤ 197.6
197.6 < Q ≤ 304.0
Q > 304.0
Maximum
Minimum
rq
(Q – 106.4) * 0.0026
(Q – 106.4) * 0.0010
(Q – 197.6) * 0.0007 + 0.0912
(Q – 304.0) * 0.0003 + 0.1657
30%
g
Can be negative
69



A well
ll event reports the
h following
f ll i
for
f production
d
i
month
h
January 2009
Raw gas production:
900 103m3
Fi ld condensate
Field
d
production:
d
i
20 m3.
Convert the raw gas production to a condensate equivalent
volume, as follows:
= 900 103m3 / 0.78783 = 1,142.378 m3
Add the converted raw gas to the field condensate liquid
volume:
Q = 1,142.378
,
m3 + 20 m3 = 1,162.378
,
m3
70





Raw gas production:
Field condensate production:
Convert the raw gas to a condensate volume:= 47.00 103m3/0.78783
= 59.6575 m3 (add this amount to the field
f
condensate volume)
Q = 59.6575 m3 + 21.0 m3 = 80.6575 m3
Quantityy (m
Q
( 3/month))
Q ≤ 106.4
106.4 < Q ≤ 197.6
197.6 < Q ≤ 304.0
Q > 304.0


47.00 103m3
21.0 m3
rq
(Q – 106.4) * 0.0026
(Q – 106.4) * 0.0010
(Q – 197.6) * 0.0007 + 0.0912
(Q – 304.0) * 0.0003 + 0.1657
rq = (Q – 106.4) * 0.0026 = (80.6575 – 106.4) * 0.0026
= -6.693%.
72




Raw gas production:
Field condensate production:
Convert the raw gas to a condensate volume: 105.00 103 m3/0.78783
= 133.2775
133 2775 m3 (add this amount to the field condensate volume)
Q = 133.2775 m3 + 32.0 m3 = 165.2775 m3
Quantity (m3/month)
Q ≤ 106.4
106 4
106.4 < Q ≤ 197.6
197.6 < Q ≤ 304.0
Q > 304
0
304.0


105.00 103m3
32.0
32 0 m3
rq
(Q – 106.4)
106 4) * 00.0026
0026
(Q – 106.4) * 0.0010
(Q – 197.6) * 0.0007 + 0.0912
(Q – 304
0) * 00.0003
0003 + 00.1657
1657
304.0)
rq = (Q – 106.4) * 0.0010 = (165.2775 – 106.4) * 0.0010
= 5.888%.
73




Raw gas production:
Field condensate production:
Convert the raw gas to a condensate volume: 216.0 103m3/0.78783
= 274.1708
274 1708 m3 (add this amount to the field condensate volume)
Q = 274.1708 m3 + 12.0 m3 = 286.1708 m3
Quantity (m3/month)
Q ≤ 106.4
106 4
106.4 < Q ≤ 197.6
197.6 < Q ≤ 304.0
Q > 304
0
304.0


216.00 103m3
12.0
12 0 m3
rq
(Q – 106.4)
106 4) * 00.0026
0026
(Q – 106.4) * 0.0010
(Q – 197.6) * 0.0007 + 0.0912
(Q – 304
0) * 00.0003
0003 + 00.1657
1657
304.0)
rq =(Q–197.6)*0.0007+0.0912 = (286.1708 197.6)*0.0007+0.0912
= 15.32%.
74








Raw gas production:
Field condensate production:
1,256.44 103m3
57.40
57 40 m3
Convert the raw gas to a condensate volume: 1,256.44 103m3/0.78783
= 1,594.811
1 594 811 m3 (add this amount to the field condensate volume)
Q = 1,594.811 m3 + 57.4 m3 = 1,652.2111 m3
Quantity (m3/month)
rq
Q ≤ 106.4
106 4
(Q – 106.4)
106 4) * 0.0026
0 0026
106.4 < Q ≤ 197.6
(Q – 106.4) * 0.0010
197.6 < Q ≤ 304.0
(Q – 197.6) * 0.0007 + 0.0912
Q > 304.0
(Q – 304.0) * 0.0003 + 0.1657
rq = (Q – 304.0) * 0.0003 + 0.1657
= (1,652.2111 – 304.0) * 0.0003 + 0.1657
= 57.02% , exceeds the cap =>
> rq = 30%.
75
Total royalty rate for field condensate:
R% = rp% + rq%
76


NRF is based on the determination of royalties
at the well event
WEARR will replace the Facility Average
Royalty Rate and Raw Gas Average Royalty
Rate which are used under the current regime
78


Definition:
WEARR is a weighted average, at the well event, of
the individual ISC product royalty rates
rates, weighted
by the ISC composition of the gas stream based
on information available at the point of royalty
determination.
The weighting of the ISC composition of the gas
stream at the facility will employ a Facility
Component Proportion (FCP)
79


Definition:
FCP is the ratio of the heat content of individual
ISC
SC products
d
to the
h totall heat
h
content off the
h gas
disposition reported at the point of royalty
y y trigger
gg
determination,, referred to as a royalty
facility
The FCP of ISC products are used to determine
the gas composition of all well events that receive
allocations from the triggered facility
80






If the PP is as follows:
Methane ISC: $6.66/GJ
Ethane ISC: $7.20/GJ
A well event reports:
CO2 content: 1.00%
H2S content: 0.05%

Raw gas:
Total heat:
Hours:

MD: 1,929m


604.50 103m3
17,552.39 GJ
744



Then rp% is as follows:
rp methane%
= 9.72%
rp ethane%
= 11.85%

AGF: CO2 + H2S
= 1.00% + 0.05% = 1.05%,
AGF is ≤ 3% => ADP is not adjusted.

ADP=(604.5/744)*24=19.50 103m3/d

DF = 1.00, since MD ≤ 2,000m


81









Since the DF = 1
ADP = 19.50 103m3/day
rq =[ADP–11]*(0.0100)+0.2500
[ADP 11]*(0 0100) 0 2500 =[19.50–11]*(0.0100)+0.2500
[19 50 11]*(0 0100) 0 2500
= 33.50%, exceeds the cap => rq = 30%
Quantity (103m3/d)
rq
ADP≤ 6
[ADP – 4]*(0.0500)
6 < ADP ≤ 11
[ADP – 6]*(0.0300)+0.1000
ADP > 11
[ADP – 11]*(0.0100)+0.2500
Rmethane% = rp methane%+rq% = 9.72% + 30% = 39.72%
Rethane
% = rp ethane
%+rq% = 11
11.85%
85% + 30% = 41
41.85%
85%
th
th
Propane ISC:
30%
Butanes ISC:
30%
Pentanes Plus ISC:
40%
82


The energy content of the ISCs at the well event
are not known or reported by the operator
The FCP method
◦ Is used to determine the WEARR at a well event
◦ Applies
pp
the g
gas composition
p
of the facility
y to
each well event which reports to this facility
83
The table below summarizes the facility to which
the well event flows

Volume (103 m3)
(2)
Heat (GJ)
(3)
FCP
(4) = (3)/(sum of all ISCs)
C1-IC
2,382.7
88,161.652
81.5798%
C2-IC
185.8
12,277.174
11.3606%
C3-IC
57 6
57.6
5 415 294
5,415.294
5 0110%
5.0110%
C4-IC
14.6
1,774.386
1.6419%
C5-IC
2.9
439.494
0.4067%
Total
2,643.6
108,068.000
100%
Product ISC
(1)
84

Applying the FCP for each of the ISC to the total
heat content for the well event
Product
(1)
Total Well Event
Heat
(2)
Calculated Facility FCP
column (4) of previous table
(3)
Well Event (GJ)
= (2) * (3)
C1-IC
17,552.39
81.5798 %
14,319.2036
C2-IC
17,552.39
11.3606 %
1,994.0569
C3-IC
17,552.39
5.0110 %
879.5513
C4-IC
C C
17,552.39
7,
. 9
1.6419
.
9%
288.1955
. 9
C5-IC
17,552.39
0.4067 %
71.3826
100.00 %
17,552.3900
Total
85
Product Heat content (GJ)
(1)
(2)
C1-IC
C2 IC
C2-IC
C3-IC
C4-IC
C C
C5-IC
Total



14,319.2036
1 994 0569
1,994.0569
879.5513
288.1955
71.3826
1 3826
17,552.39 GJ (6)
ISC Calculated
Royalty Rate
(3)
Royalty Heat (GJ)
(4) = (2) * (3)
39.72 %
41 85 %
41.85
30 %
30 %
40 %
5,687.5877
834 5128
834.5128
263.8654
86.4587
28 30
28.5530
6,900.9776 GJ (5)
WEARR = Royalty heat/Total heat content
= (5)/(6) = 6,900.9776/17,552.39 × 100
= 39.3165%
86



Solution g
gas will continue to be treated the same as
natural gas
Except that the ADP will be based upon the well
event total production of both the solution gas and
the gas equivalent energy content of conventional
oil or bitumen
WEARR: is determined as in the previous example
87



Flow split is where a well event has disposition
to multiple ERCB facilities
f
There can be more than one WEARR calculated
based on the ISC dispositions at each facility
The following is an example to illustrate this
situation
88



If the PP is as follows:
Methane ISC: $6.66/GJ
Ethane ISC: $7.20/GJ








Then rp% is as follows:
f
rp methane%
= 9.72%
rp ethane%
= 11.85%



A well event reports:
CO2 content: 1.00%
H2S content: 0.05%
Raw gas:
604.50 103m3
Total heat: 17, 552.39 GJ
Hours:
744
MD:
1,929m
This well event is the same as the previous WEARR Example 1, thus:
◦ Methane ISC:
39.72%
◦ Ethane ISC:
41.85%
◦ Propane ISC:
30%
◦ Butanes ISC:
30%
◦ Pentanes Plus ISC: 40%
89
Product ISC
(1)
C1-IC
C2-IC
C3-IC
C4-IC
C5-IC
Total
Volume (103 m3)
(2)
442.67473
64.491912
29.25418
9.9099829
3.2211561
549.55196
Heat (GJ)
(3)
18,149.66
2,644.17
1,199.42
406.3093
132.0674
22,531.63
FCP
(4) = (3)/(sum of all ISCs)
80.5519 %
11.7354 %
5.3233 %
1.8033 %
0.5861 %
100 %
Product ISC
(1)
C1-IC
C2-IC
C3-IC
C4-IC
C5-IC
Total
Volume (103 m3)
(2)
35,897.172
2,815.7965
1,005.8017
407.78468
186.96876
40,313.52364
Heat (GJ)
(3)
14,717.840
1,154.477
412.3787
167.1917
76.65719
16,528.540
FCP
(4) = (3)/(sum of all ISCs)
89.0450 %
6.9847 %
2.4949 %
1.0115 %
0.4638 %
100%
90



The well event in this example sends its volumes
to both GP0001000 and GP0001001.
The total heat content production for this well
event is 17, 552.39 GJ for the month.
Of this amount:
◦ GP0001000: 76.7%
76 7% =>
> 13,462.68313
13 462 68313 GJ
◦ GP0001001: 23.3% =>
4,089.70687 GJ
91
Product
(1)
C1-IC
C2-IC
C3-IC
C3 IC
C4-IC
C5-IC
Total
Product
(1)
C1-IC
C2-IC
C3 IC
C3-IC
C4-IC
C5-IC
Total
Total Well Event Heat
(2)
13,462.68313
13,462.68313
13
462 68313
13,462.68313
13,462.68313
13,462.68313
Total Well Event Heat
(2)
4,089.70687
4,089.70687
4 089 70687
4,089.70687
4,089.70687
4,089.70687
Calculated Facility FCP
column (4) of previous table
(3)
80.5519 %
11.7354 %
55.3233
3233 %
1.8033 %
0.5861 %
100 %
Calculated Facility FCP
column (4) of previous table
(3)
89.0450 %
6.9847 %
2 4949 %
2.4949
1.0115 %
0.4638 %
100%
Well Event (GJ)
= (2) * (3)
(4)
10,844.4494
1,579.8944
716
6559
716.6559
242.7704
78.9105
13,462.68313
Well Event (GJ)
= (2) * (3)
(4)
3,641.6799
285.6558
102 0361
102.0361
41.3687
18.9675
4,089.70687
92
Product
P d t
(1)
Heat
H t content
t t (GJ)
(Last slide (4))
(2)
C1-IC
C1
IC
C2-IC
C3-IC
C4 IC
C4-IC
C5-IC
Total



10,844.4494
10
844 4494
1,579.8944
716.6559
242 7704
242.7704
78.9105
13,462.6831 GJ (6)
ISC Calculated
C l l t d
Royalty Rate
(3)
39 72 %
39.72
41.85 %
30 %
30 %
40 %
Royalty
R
lt H
Heatt (GJ)
(4) = (2) * (3)
44,307.4153
307 4153
661.1858
214.9968
72 8311
72.8311
31.5642
5,287.9932 GJ (5)
WEARR = Royalty heat/Total heat content
=(5)/(6)=5,287.9932/13,462.6831×100
=39.2789%
39 2789%
93
Product
P d t
(1)
C1-IC
C1
IC
C2-IC
C3-IC
C4 IC
C4-IC
C5-IC
Total



Heat
H t content
t t (GJ)
(Last slide (4))
(2)
3 641 6799
3,641.6799
285.6558
102.0361
41 3687
41.3687
18.9675
4,089.7068 GJ (6)
ISC Calculated
C l l t d
Royalty Rate
(3)
39 72 %
39.72
41.85 %
30 %
30 %
40 %
Royalty
R
lt Heat
H t (GJ)
(4) = (2) * (3)
11,446.4752
446 4752
119.5469
30.6108
12 4106
12.4106
7.5870
1,616.6306 GJ (5)
WEARR = Royalty heat/Total heat content
=(5)/(6)=1,616.6306/4,089.7069 × 100
= 39.5293
39 5293 %
94


Production entities are units, well groups and
injection schemes
A WEARR is calculated for each well event within
the entity based on the FCP and rolled-up to
determine a weighted aggregate royalty rate of
the PE
95


In
I this
thi example,
l there
th
are 5 well
ll events
t and
d a unit
it
that deliver natural gas to a GP
The GP reports the following in-stream components:
Product ISC
(1)
C1-IC
C2-IC
C3-IC
C4
C4-IC
IC
C5-IC
Total
Volume (103m3)
(2)
2,382.7
185.8
57.6
14
14.6
6
2.9
2,643.6
Heat (GJ)
(3)
88,161.652
12,277.174
5,415.294
11,774.386
774 386
439.494
108,068.000
FCP
(4) = (3)/(sum of all ISCs)
81.5798%
11.3606%
5.0110%
11.6419%
6419%
0.4067%
100%
96

The GP allocates the following volumes and heats
to each of the well events and units tied to it
Stream
(1)
Well Event 1
Well Event 2
Well Event 3
Well Event 4
Well Event 5
Unit 1
Total
Volume (103 m3)
(2)
Heat (GJ)
(3)
429.220
69.937
161.895
395.909
514.406
1,072.233
2,643.600
17,550.396
2,898.382
6,648.342
16,190.750
,
21,008.230
43,771.900
108,068.000
% Contribution of
Reporting Facility Heat
(4)
16.2401%
2.6820%
6.1520%
14.9820%
19.4398%
40.5040%
100.00%
97


Based on the heat allocation to Unit 1 of
43,771.900 GJ and the FCP
Th ISC allocation
The
ll
ti
for
f the
th unit
it can be
b determined
d t
i d
as follows:
Product Total Unit Heat (GJ)
(1)
(2)
C1-IC
C2-IC
C3-IC
C4-IC
C5-IC
Total
,
43,771.9
43,771.9
43,771.9
43,771.9
43,771.9
FCP
(3)
81.5798%
11.3606%
5.0110%
1.6419%
0.4067%
100%
Unit Heat
Distribution
(4) = (2) * (3)
35,709.03
,
4,972.75
2,193.41
718.69
178.02
43,771.90
98

To determine the estimated heat for each well
events within the unit.
unit
Well Event
Tie
Well Event A
Well
ll Event B
Well Event C
Well Event D
W
ll E
Well
Eventt E
Total
Reported Raw Gas
Production (103m3)
(1)
324.53
74.89
4 89
131.48
336.18
292
91
292.91
1,159.99 (4)
%Contribution to Unit
(2) = (1)/(4)
Heat (GJ)
(3) = (2)*(5)
27.9770%
6 4 61%
6.4561%
11.3346%
28.9813%
25
2511%
25.2511%
100%
12,246.0493
2 82 9 33
2,825.9533
4,961.3612
12,685.6588
11 052 8774
11,052.8774
43,771.90 (5)
99

Using the
h heat
h
derived
d
d for
f each
h well
ll event in the
h
previous slide and the FCP, the ISC heat is determined
for each of the well events within the unit:
FCP
(1)
C1-IC
C2-IC
C3 IC
C3-IC
C4-IC
C5-IC
Total
81.58%
11.36%
5 01%
5.01%
1.64%
0.41%
100%
A
=(1)*(7)
Well Event (GJ)
B
C
D
=(1)*(8)
=(1)*(9)
=(1)*(10)
Total
=(A+ … +E)
E
=(1)*(11)
9,990.30
1,391.22
613 65
613.65
201.07
49.80
2,305.40
321.05
141 61
141.61
46.40
11.49
4,047.47
563.64
248 61
248.61
81.46
20.18
10,348.94
1,441.17
635 68
635.68
208.29
51.59
9,016.92
1,255.67
553 86
553.86
181.48
44.95
35,709.03
4,972.75
2 193 41
2,193.41
718.70
178.01
12,246.04
12
246 04
(7)
22,825.95
825 95
(8)
44,961.36
961 36
(9)
12
12,685.67
685 67
(10)
11
11,052.88
052 88
(11)
43
43,771.90
771 90
100

The PP and relevant information reported by the
operator of each well event, within the unit, are as
follows:
Input for Unit 1
C1 Par Price
C2 Par Price
CO2 content
H2S content
AGF
Raw gas production
(103m3 for the month)
p
Hours of production
ADP (103 m3/day)
MD (meters)
Depth Factor
A
$6.66
$7.20
1%
0%
1 00
1.00
324.53
B
$6.66
$7.20
0%
2.21%
1 00
1.00
74.89
620
12.5625
1,500
1.00
562
3.1981
2,566
1.6461
Well Event
C
$6.66
$7.20
2%
0%
1 00
1.00
131.48
744
4.2413
3,152
2.4838
D
$6.66
$7.20
2.95%
0%
1 00
1.00
336.18
E
$6.66
$7.20
0%
0%
1 00
1.00
229.91
701
11.5097
1,956
1.00
657
8.3985
1,927
1.00
101


Based on the information in the previous slide
The following 2 slides display each well event’s
royalty rates for methane and ethane and their
respective
p
weighted
g
averages
g for the unit
102
C1
(1) rp
(2) rq
(3) = (1)+(2)
R% = rp + rq
(4) C1-IC (GJ)
(5) = (3)*(4)
Royalty Liable
GJ
(6) = (8)/(9)
Weighted %
A
B
Well Event
C
9.72%
26.56%
36 28%
36.28%
9.72%
-10.29%
5 00%
5.00%
9.72%
-11.46%
5 00%
5.00%
9.72%
25.5097%
35 23%
35.23%
9,990.30
2,305.41
4,047.47
10,348.94 9,016.92 35,709.03
(9)
33,624.73
624 73
115 2
115.2
202
37
202.37
Total
D
E
9.72%
17.20%
26 92%
26.92%
33,645.90
645 90
10,015.23
22,426.96
426 96
(8)
28.0468%
103
C2
(1) rp
(2) rq
(3) = (1)+(2)
R% = rp + rq
(4) C2-IC (GJ)
(5) = (3)*(4)
Royalty Liable
GJ
(6) = (8)/(9)
Weighted %
A
B
11.85%
26.56%
38.41%
11.85%
-10.29%
5.00%
1,391.22
534.40
Well Event
C
Total
D
E
11.85%
-11.46%
5.00%
11.85%
25.51%
37.36%
11.85%
17.1956%
29.05%
321.05
563.64
1,441.17
1,255.67
16.05
28.18
538.42
364.72
4,972.75
(9)
1,481.77
(8)
29.7978%
104

The Unit WEARR is the weighted average royalty rate
for all the well events where the weightings are
p
the individual heat content of the ISCs.
based upon
Product Heat content (GJ)
(1)
(2)
C1-IC
C2-IC
C3-IC
C3
IC
C4-IC
C5-IC
Total
35,709.03
4,972.75
2 193 41
2,193.41
718.69
178.02
43,771.90 GJ (6)



ISC Calculated
Royalty Rate
(3)
28.0468%
29.7978%
30 %
30 %
40 %
Royalty Heat (GJ)
(4) = (2) * (3)
10,015.24
1,481.77
658 02
658.02
215.61
71.21
12,441.85 GJ (5)
WEARR = Royalty heat/Total heat content
=(5)/(6)=12,441.85/43,771.90×100
= 28.4243%
105


The WEARR for RGA is calculated based on the
ISC factors on the RGA submission in the PRA,
reported by the seller.
For natural gas that is sold in its raw
(unprocessed) state
state, the point of determination
for royalties continues to be at the point of sale.
106
107


The valuation price for gas is a facility average of
the individual ISC product reference prices,
weighted by the ISC composition,
composition subject to a gas
transportation adjustment for each ERCB facility.
The determination, calculation, and use of the FAP
remains unchanged under the NRF
108

Under the NRF the par and reference prices will
continue to be determined as they are under the
current royalty regime, by the department.
109



Under the current royalty regime a new royalty client
has the option of choosing either the Reference Price
or the CAP valuation method
method.
A royalty client’s CAP is based upon its total gas sales
value divided by its total gas sales volume, subject to
a minimum of 90% of the gas reference price.
Under NRF the CAP will be terminated
terminated, all royalty
clients will pay royalties based on the reference price
110
The
Th value
l charged
h
d to royalty
l clients,
li
as a gross
amount, is:


Natural gas (all ISCs) and solution gas:
Royalty Valuation = Crown heat × WEARR × FAP,
Where: Crown heat = Client heat × Crown Interest.
Extracted ethane
ethane, propane
propane, butanes and pentanes plus
= Crown volume × royalty rate × reference price
112


Raw gas:
= Crown heat × RGAWEARR × 80% of gas reference price
Field condensate:
= Crown royalty
y y volume × p
pentanes p
plus reference p
price
113


Assume
A
the
h following
f ll i
for
f a royalty
l client:
li
◦ Crown Heat: 351.0 GJ
◦ WEARR:
39.038%
◦ FAP:
$6.66
Royalty Valuation
= Crown Heat × WEARR × FAP
= 351×39
351×39.038×6.66
038×6 66 = $912
$912.58
58
114