Marginal Royalty Program

Qualification Criteria:

(4) A well event is a marginal well event if

(a) the well event is a gas well event,

 

(b) the result of the following calculation is less than 23m³ for every metre of marginal well depth:

where

 

TP means the total production from the well event in the following applicable period:

(i) if the well event is not a reactivated well event, the period of 12 consecutive calendar months that begins with the calendar month in which marketable gas is first produced from the well event

(ii) if the well event is a reactivated well event, the period of 12 consecutive calendar months that begins with the calendar month in which the reactivated well event commenced or recommenced producing, and

TPH means the total number of hours during which the well event produced natural gas in that 12 calendar month period,.

(c) the 12 calendar month period referred to in paragraph (b) ends after June 30, 2004,   

             

(d) the well event is in a well that has a spud date after May 31m 1998, and

 

(e) the well event is not an ultramarginal well event and is not part of a coalbed methane project.

Where the following terms are defined:

 “Marginal well depth” means, for a marginal well event,

(a) for a vertical well, the distance between the wellbore’s intersection with the top of the productive zone of the marginal well event to the point, directly above that intersection point, that is the same elevation as the kelly bushing used in drilling that well, and

 

(b) for a horizontal well, the sum of the lengths of all of the vertically oriented and horizontally oriented wellbores that constitute the marginal well event, which sum is commonly referred to as the total measured depth;

“Reactivated well event” means any well event that:

                       (a)  was suspended or abandoned on or before June 30, 2003.

                       (b) was, after that date, put back into production.

“Well event” means all completions in a zone for a well with a primary product of natural gas.

"Horizontal well" means a well that meets the following criteria:

(a)  a wellbore in the well is drilled at an angle of at least 80 degrees from vertical, and, for the purposes of this paragraph, the wellbore is deemed to be a line connecting the wellbore’s initial point of penetration into a productive zone to the wellbore’s end point in that productive zone.

 

(b)  the length of the wellbore referred to in paragraph (a) is at least 100 metres, measured from the wellbore’s initial point of penetration into the productive zone referred to in paragraph (a) to the wellbore’s end point in that productive zone.

"Vertical well" means any well that is not a horizontal well.

Royalty Calculation:

Each marginal well also gets a low productivity reduction factor (LPRF) against the royalty percentage in accordance with the following formula:

LPRF = [(25000 - S) / 25000]²

where

Example: 

Well Event in Zone A

Horizontal Well

Total Measured Depth = 1,500m

Total production in Year One: 5,100x10³m³

Total Producing Hours over Year One: 5,000 hours

Threshold Calculation:   (5,100,000 m³*24 hours)/5,000 hours x 1,500 m = 16.3 m3 per day per metre of well

depth

The Well Event in Zone A is less than 23 m3 per day per metre of well depth.  Therefore, all average daily production less than 25x 10³m³ per day would be eligible for the marginal royalty calculation. 

Now calculate the Marginal Royalty for the Well Event in Zone A for July, 2004. 

Average Daily Raw Gas in July, 2004: 17 x 10³m³

Marginal Select Price: $50 per 10³m³

Reference Price:            $210 per 10³m³

Part A: Initial Royalty Percentage calculation: 

Royalty Percentage =    9 x SP + 40 (RP – SP)
                               RP

This rate is subject to a minimum of 9% and Maximum of 27%. 

Where

RP = REFERENCE PRICE

SP = 50

Royalty Percentage =    9 x 50 + 40 (210 – 50)   =  32.6% -->27%
                               210

Part B: Low Productivity Reduction Factor:

LPRF = [(25000 - S) / 25000]²

where

S is equal to the lesser of the average daily natural gas production volume for the marginal well in the producing

month and 25,000.

Also S < 25,000 m³ to qualify for a reduction.

LPRF = [(25000-17000)/25000]² = .1024

Final Royalty Percentage: 27% - .1024*27% = 24.24% for all production out of Zone A.