Royalty Information for wells spud up to and including December 31, 2016


These questions represent the policy intent of the Government of Alberta. The questions are subject to change. Regulations prevail over these questions.

The term spud date refers to the day the drill bit hits the ground or when an existing well is re-entered, as defined by Alberta Energy Regulator’s Directive 059.

Changes to the Alberta Royalty Framework royalty rates were effective for the January, 2011 production month.

Changes to the Natural Gas Deep Drilling Program were effective on May 1, 2010.

The Emerging Resources and Technologies Initiatives for Shale Gas, Coalbed Methane, Horizontal Oil  and Horizontal Gas wells were all effective on May 1, 2010.

Non-project oil sands well events subject to royalty calculation under section 27 of the Oil Sands Royalty Regulation 2009, moved to adjusted ARF royalty rates with the January 2011 production month. Project oil sands wells were not affected.

Well events royalties prior to 2011 were calculated under the Natural Gas Royalty Regulation 2009, or the Petroleum Royalty Regulation 2009. (Note: regulations can be viewed in html or PDF with no charge, other formats may be subject to additional fees.)

The Modernized Royalty Framework came into effect on January 1, 2017.

Frequently Asked Questions

General Royalty Questions

Which programs were offered a 5% royalty rate for the first year and why was this offered?

The New Well Royalty Rate of 5% for the first year was a feature of the Alberta Royalty Framework.

The New Well Royalty Rate was extended to Coalbed Methane wells to encourage new exploration, development, and production from Alberta’s gas resources within coal seams.  Alberta has a large resource base of CBM estimated at over 500 trillion cubic feet (Tcf).  While there has been active development in some of the shallow dry portions of this resource, the largest potential in the deeper coal seams has not received significant development.  These deeper coal seams tend to contain saline water that impacts production thus impacting costs and well economics.  The presence of water necessitates a dewatering phase prior to a well achieving its maximum production rates.  An extension of the 5% front end rate for these wells was introduced to accommodate this dewatering phase.

The 5% New Well Royalty Rate was also extended to new Horizontal Oil and Gas well events to further encourage the deployment of new horizontal technologies in the development and production from Alberta’s resources.

The rate provides a lower upfront royalty rate at the start of production to facilitate the recovery of investment costs prior to imposing a higher royalty rate. Horizontal drilling increases the cost and the technical risks for wells. Extension of the 5% front end rate for these wells has been introduced to accommodate these additional costs.

Throughout North America a transition to horizontal drilling has been occurring in an attempt to better access lower permeability resources.  Many of Alberta’s producing formations have been predominantly pursued with vertical wells.  The application of horizontal wells to these formations may allow the development of some of these resources at reduced costs potentially allowing development in Alberta to compete with other locations.
For oil several opportunities exist including the Cardium and the Viking formations.
The New Well Royalty Rate and Shale Gas New Well Royalty Rate will run concurrently. Therefore, a qualified well event under New Well Royalty Rate and the Shale Gas New Well Royalty Rate would have a maximum of 36 production months at 5%.

Some volume caps are expressed in metres cubed oil equivalent. How are gas volumes converted to cubic metres of oil equivalent?

To convert an energy-adjusted gas equivalent volume (103m3) to an oil equivalent volume (m3), divide by 1.7811 to obtain the oil equivalent volume (m3).
To convert a gas volume (MMcf) to an oil equivalent volume (m3), first convert from MMcf to energy-adjusted gas equivalent volume (103m3) by multiplying the volume by 28.316 and then divide the result by 1.7811 to obtain the oil equivalent volume (m3).

Some volume caps are expressed in metres cubed oil equivalent. How are condensate volumes converted to cubic metres of oil equivalent?

To convert a condensate volume (m3) to an oil equivalent volume (m3), first multiply by 0.20570 to obtain the gas equivalent volume (103m3). Next multiply by energy adjustment factor 3.83 to obtain the energy-adjusted gas equivalent volume  (103m3). Finally, divide the result by 1.7811 to obtain the oil equivalent volume (m3).

Some volume caps are expressed in metres cubed oil equivalent. How are natural gas liquids (NGL) volumes converted to cubic metres of oil equivalent?

NGL volumes are converted to cubic metres of oil equivalent volumes as follows:

  1. Multiply the liquid volume (m3) by the Gas Equivalent Factor to obtain the gas equivalent volume (103m3).
  2. Multiply by the Energy Adjustment Factor to obtain the energy-adjusted gas equivalent volume (103m3).
  3. Final step, divide the result by 1.7811 to obtain the oil equivalent volume (m3).

Gas and Gas Products

Gas Equivalent Factor

Energy Adjustment Factor

Gas in 103m3

1.00000

1.00

Ethane

0.28132

1.00

Propane

0.27201

2.41

Butane

0.23331

3.12

Pentanes-Plus in m3

0.20570

3.83

Sulphur

0.73750

1.00

Other

0.00000

0.00

 

Why are oil equivalent volumes specified in royalty programs meant mainly for gas well events?

All products subject to payment of royalties that are produced from the well event apply to the program’s volume cap. As a result, all volumes must be converted to a common unit of measure. Cubic metres were currently used in the New Well Royalty Reduction Regulation which had a similarly structured volume cap. Business rules and regulations are simplified by ensuring that the new royalty programs are implemented consistently.

For wells qualifying for both the NGDDP and any of the 5% royalty rates, including the New Well Royalty Rate (NWRR), the Horizontal Gas NWRR, the Coal Bed Methane NWRR or the Shale Gas NWRR, how are royalties calculated?

Where a well qualifies for both the NGDDP and any of the 5% royalty rates, the 5% royalty rate will be applied first, with the NGDDP benefits applied after the expiration of the 5% rate. However, the 60 calendar month benefit under the NGDDP begins on the well’s finished drilling date, not with the expiry of the 5% royalty rate.

New Well Royalty Rate (NWRR) Questions

Which wells qualified for the NWRR rate?

A well will qualify if it meets all of the following criteria:

Note: For the purposes of determining eligibility for recommencement, the requirement for no production refers to total production.

  Description
  • For wells spud up to and including December 31, 2016
  • Commenced production on or after April 1, 2009
  • No prior production is permitted (other than excluded production)
  • Recommences production on or after April 1, 2009 to March 31, 2011
  • No production during the period January 1, 2007 to March 31, 2009 (other than excluded production)      
  • Recommences production on or after April 1, 2009 to March 31, 2011
  • No production during the period January 1, 2009 to March 31, 2009 (other than excluded production)
  • Total average monthly production (converted into equivalent cubic metres of oil using a factor of 1.0686 of gas) is less than 100 cubic metres during the last 3 production months within the period January 1, 2007 to December 31, 2008
  • For wells spud up to and including December 31, 2016
  • Commenced production on or after April 1, 2011
  • No production during the 36 consecutive months prior to the first month of production (other than excluded production)
E
  • For wells spud up to and including December 31, 2016
  • Commenced production on or after April 1, 2011
  • No production during the period January 1, 2009 to March 31, 2011 production (other than excluded).
  • Total average monthly production (converted into equivalent cubic metres of oil using a factor of 1.0686 of gas) is less than 100 cubic metres during the last 3 production months within the period January 1, 2007 to December 31, 2008.

 

Why are there restrictions for re-entry, suspended and inactive wells?

The New Well Royalty Rate was not intended to apply to wells that were already producing and connected to infrastructure that may have been offline for various reasons. The policy intent of the New Well Royalty Rate is to encourage production that would not otherwise happen. Re-entry, suspended or inactive wells that were shut-in, not producing because they were uneconomic, or would require some additional investment in the well to be brought on line, qualify as this production would not have occurred without the New Well Royalty Rate.

Is there a drilling date requirement to receive the New Well Royalty Rate?

No. Qualification for the New Well Royalty Rate does not depend on when the well was drilled. If a new well came on production in March 2011, there is no time constraint imposed to reach 12 production months.

Are there any wells that do not qualify for the New Well Royalty Rate?

The following are examples of wells that do not qualify for the New Well Royalty Rate:

  • Oil sands project wells (subject to the payment of royalty under the Oil Sands Royalty Regulation, 2009 or
  • Gas over bitumen wells that receive royalty adjustment because of an AER shut-in order, or
  • wells that previously reached either the volume or production month cap under the New Well Royalty Rate.

Natural Gas Deep Drilling Program Questions

Why is the Government of Alberta making changes to the NGDDP?

The intent of the Natural Gas Deep Drilling Program (NGDDP) is to encourage new exploration, development, and production from deeper and high cost natural gas wells. Adjustments for deep natural gas wells have existed since 1985. The NGDDP was originally introduced in 2009. Modifications to this program are intended to promote the development of new resources identified through drilling and to reflect the costs for all of the productive drilling in these wells.

One of the principle new targets of the NGDDP is the Alberta Cretaceous Deep Basin. A study by Petrel Robertson indicated that the Deep Basin contains about 425 trillion cubic feet (Tcf) of natural gas.  Of this roughly one quarter (108 Tcf) is estimated to exist between a vertical depth of 2,000 metres and 2,500 metres. Wells that have producing intervals that exceed 2,000 metres True Vertical Depth (TVD) are now eligible under this program.

What qualifies and what doesn’t under the royalty adjustment?

The well must;

  • be a natural gas well with a gas-oil ratio of greater than 1,800 : 1 and,
  • have a Crown interest greater than zero, and
  • have been  spud or deepened on or after May 1, 2010, and
  • have a TVD greater than 2,000 metres

The following does not qualify under the royalty adjustment

  • dry holes
  • oil wells producing oil only or with gas at a gas-oil ratio of less than 1800:1
  • crude bitumen wells

What is the revised NGDDP benefit schedule for a development well?

NGDDP Royalty Adjustment Per Well Development Wells
Benefit per metre drilled in the depth range ($/m) 

Measured Depth (metres) 

  >2,000 – 3,500

   >3,500 – 4,000 

   >4,000 – 5,000 

   >5,000 

>2,000

     $625

 

 

 

>3,000 

     $625 

 

 

 

>3,500 

     $625 

     $2,500

 

 

>4,000 

     $625 

     $2,500 

    $2,500 

 

>4,500 

     $625

     $2,500 

    $2,500 

 

>5,000

     $625

     $2,500

    $2,500

    $3,000

For development wells with depths greater than 2,000 m and less than or equal to 3,500 m the available benefits are calculated by taking the measured depth (MD) of the well minus 2,000 m and multiplying this result by $625/m.

For development wells with depths greater than 3,500 m and less than or equal to 5,000 m the available  benefits are calculated by taking the measured depth greater than 3,500 m, multiplying this result by $2,500/m and adding $937,500 ($937,500 being the result from the calculation for the 2,000 m – 3,500 m drilled depth range).

For development wells with depths greater than 5,000 m the available benefits are calculated by taking the measured depth minus 5,000 m, multiplying this result by $3,000/m and adding $4,687,500. 

What is the revised NGDDP benefit schedule for an exploratory well?

NGDDP Royalty Adjustment Per Well Exploratory Wells
Benefit per metre drilled in the depth range ($/m)

Measured Depth (metres)

 >2,000 – 3,500

   >3,500 – 4,000 

    >4,000 – 5,000 

  >5,000 

>2,000

     $625

 

 

 

>3,000 

     $625 

 

 

 

>3,500 

     $625 

     $2,500

 

 

>4,000 

     $625 

     $2,500 

    $3,125 

 

>4,500 

     $625

     $2,500 

    $3,125 

 

>5,000

     $625

     $2,500

    $3,125

    $3,750

For exploratory wells with depths greater than 2,000 m and less than or equal to 3,500 m the available benefits are calculated by taking the measured depth (MD) of the well minus 2,000 m and multiplying this result by $625/m.

For exploratory wells with depths greater than 3,500 m and less than or equal to 4,000 m the available benefits are calculated by taking the measured depth minus 3,500 m, multiplying this result by $2,500/m and adding $937,500. ($937,500 being the result from the calculation for the 2,000 m – 3,500 m drilled depth range.)

For exploratory wells with depths greater than 4,000 m and less than or equal to 5,000 m the available benefits are calculated by taking the measured depth minus 4,000 m, multiplying this result by $3,125/m and adding $2,187,500.

For exploratory wells with depths greater than 5,000 m the available benefits are calculated by taking the measured depth minus 5,000 m, multiplying this result by $3,750/m and then adding $5,312,500.

Will the supplemental adjustment be given to any well?

The supplemental adjustment of $875,000 will be given to wells that have a spud date on or before May 27, 2010 with a depth of  4,000 metres or greater.

How is the measured depth determined for the purpose of benefit calculations?

The depth is based on the sum of the length, in metres, from the kelly bushing of the well to the base of the deepest producing interval in the well.  Wells spud on or after May 1, 2010 that have additional legs will receive an additional benefit based on the sum of the lengths, in metres, of all other laterals in the well from the kick-off point of each lateral to the perforation that is furthest from the kick-off point.

Note: Examples below illustrate how the royalty adjustment is calculated using the measured depth of the deepest leg and the sums of the lengths of the laterals.

Are measured depths of all laterals eligible for the NGDDP?

Yes. Additional producing laterals would get a $/m royalty adjustment based on the TVD of the lateral (for example, less than 3,500 m gets $625/m and 3,500 m or deeper gets $2,500/m).

Benefits for Additional Laterals 

Qualifying true vertical depth (TVD of the Well Event) 

Benefit per drilled metre (Measured Depth –
Kick off Point of the Well Event)

 < 3,500

 $625

 >=3,500

 $2,500

The laterals’ producing interval must exceed 2000 m TVD. TVD is the vertical distance,
measured in a perpendicular line from the kelly bushing of a well to the base of the deepest producing interval.

Example 1 - Exploratory well with 2 well events

Example 1 diagram for gas curvesWell event/0 has a TVD of 3,500 m and MD of 3,600 m.  Well event/2 has a TVD of 3,600 m and MD of 3,800 m. Both events report the gas production and qualify for the NGDDP benefits.

 Benefit of the deepest lateral well event/2:

For the MD between 2,000<Depth<=3,500 the amount equals to (3,500 m- 2,000 m)* $625/m= $937,500.

For the MD between 3,500<Depth<=4,000 the amount equals to (3,800 m- 3,500 m)* $2,500/m= $750,000.

Total benefit is $1,687,500.

The measured depth at the start of the additional leg is 2,300 m. Therefore, the length of the laterals from the kick-off point to the perforation is 1,300 m (3,600 – 2,300).

Benefit of the additional leg:

For the TVD >=3,500 m the amount equals to 1,300 m* $2,500/m=$3,250,000.

Total royalty adjustment for this well is $4,937,500 ($1,687,500 + $3,250,000). 

Example 2 - Exploratory well with 1 well event

Example 2 DiagramWell event/0 has a TVD of 3,700 m and MD of 4,200 m. An event reports production of gas and qualifies for the NGDDP benefits.

 Benefit for the well event is calculated as follows:

For the MD between 2,000<Depth<=3,500 the amount equals to (3,500 m- 2,000 m)* $625/m= $937,500.

For the MD between 3,500<Depth<=4,000 the amount equals to (4,000 m- 3,500 m)* $2,500/m= $1,250,000.

For the MD between 4,000<Depth<=5,000 the amount equals to (4,200 m- 4,000 m)* $3,125/m= $625,000.

 Total royalty adjustment for this well $2,812,500.

Example 3 - A Development well with 2 well events

Example 3 diagram Well event/0 has a TVD of 3,700 m and MD of 4,200 m.  Well event/2 has a TVD < 2,000 m and MD of 2,600 m. Both events report gas production but only well event/0 qualifies for the NGDDP benefits. Because event 2 is less than 2,000 m TVD, no lateral benefit is applied. 

Benefit of the well event/0:

For the MD between 2,000<Depth<=3,500 the amount equals to (3,500 m- 2,000 m)* $625/m= $937,500.

For the MD between 3,500<Depth<=4,000 the amount equals to (4,000 m- 3,500 m)* $2,500/m= $1,250,000.

For the MD between 4,000<Depth<=5,000 the amount equals to (4,200 m- 4,000 m)* $2,500/m= $500,000.

Total royalty adjustment for this well is $2,687,500.

Example 4 - A Development well with a deepening situation

Example 4 deepening diagramA well event/0 with FDD in January 2009 has a TVD of 2,900 m and MD of 3,400 m.  Well event/2 with FDD in July 2010 has a TVD of 5,000 m and MD of 7,000 m. Both events report gas production and qualify for the NGDDP benefits.

Benefit of the well event/0:
For the MD between 2,500<Depth<=3,500 the amount equals to (3,400 m- 2,500 m)* $625/m=$562,500.
Starting January 2009 the well is eligible to receive royalty adjustments for 5 years until December 2013.

Well event/2 is the deepening situation. Once FDD is determined well event/2 becomes the longest lateral and the new FDD establishes the new effective date of the 5 year limit.
Royalty adjustment for the longest lateral is calculated as follows:
For the MD between 2,000<Depth<=3,500 the amount equals to (3,500 m- 2,000 m)* $625/m= $937,500.
For the MD between 3,500<Depth<=4,000 the amount equals to (4,000 m- 3,500 m)* $2,500/m= $1,250,000.
For the MD between 4,000<Depth<=5,000 the amount equals to (5,000 m- 4,000 m)* $2,500/m= $2,500,000.
For the MD greater than 5,000 m the amount equals to (7,000 m- 5,000 m)* $3,000/m= $6,000,000.
Total royalty adjustment $10,687,500.

Now, well event/0 becomes the additional lateral. The measured depth at the start of the additional leg is 2,800 m. Therefore, the length of the laterals from the kick-off point to the perforation is 600 m (3,400 m - 2,800 m).
Benefit calculated to the sum of additional legs:
For the TVD <3,500 m the amount equals to 600 m* $625/m=$375,000.

Total royalty adjustment for this well is calculated as $11,062,500.

This exceeds the maximum allowable adjustment for development wells and therefore the benefit is reduced to the maximum which is $8,000,000.

If this well event has used any previous NGDDP benefits, this amount will be deducted from the total royalty adjustment of $8,000,000.

Example 5 - A Development well with 3 well events

Example 5 diagramWell event/0 has a TVD of 3,500 m and MD of 3,600 m.  Well event/2 has a TVD of 3,600 m and MD of 3,800 m. Well event/3 has a TVD of 3,300 m and MD of 3,400 m. All three events report gas production and qualify for the NGDDP benefits.

Benefit of the deepest lateral well event/2:

For the MD between 2,000<Depth<=3,500 the amount equals to (3,500 m- 2,000 m)* $625/m= $937,500.

For the MD between 3,500<Depth<=4,000 the amount equals to (3,800 m- 3,500 m)* $2,500/m= $750,000.

Total benefit is $1,687,500.

The measured depth at the start of the well event/ 0 leg is 2,300 m. Therefore, the length of the lateral from the kick-off point to the perforation is 1,300 m (3,600 m – 2,300 m).

Benefit of the additional leg:

For the TVD>=3,500 m the amount equals to 1,300 m* $2,500/m=$3,250,000.

The measured depth at the start of the well event/ 3 leg is 2,300 m. Therefore, the length of the lateral from the kick-off point to the perforation is 1,100 m (3,400 m-2,300 m).

Benefit of the additional leg:

For the TVD<3,500 m the amount equals to 1,100 m* $625/m=$687,500.

Total royalty adjustment for this well is $5,625,000 ($1,687,500 + $3,250,000 +$687,500).

Shale Gas New Well Royalty Rate Questions

Why is the Government of Alberta extending the 5% royalty rate beyond 12 production months for shale gas wells?

Across North America, natural gas from shale deposits have been identified as some of the most attractive new drilling targets.  Estimates of the shale gas resource in Western Canada vary from 86 trillion cubic feet (Tcf) to over 1,000 Tcf.  While there may exist large potential in Alberta, shale gas production is in the very early stages and commercial development is not likely to occur in Alberta for a number of years. 

The intent of the Shale Gas New Well Royalty Rate is to encourage new exploration, development, and production from Alberta’s shale gas resources.  This extension of the 5% royalty rate is designed to accelerate the acquisition of knowledge and ultimately to achieve commercial natural gas production from shale deposits.

What qualifies and what doesn’t under the Shale Gas New Well Royalty Rate?

To qualify, a well event must;

  • have a fluid code of "Shale Gas Only" when it commences production, and
  • have no production prior to May 1, 2010 and
  • have a Crown interest greater than zero when it commences production.
  • Re-entry, reactivated, lengthened, and deepened well events may qualify for the Shale Gas New Well Royalty Rate provided there is NO prior production from the well event. 
  • Wells that have prior production and are being brought back on DO NOT qualify

All well events that produce exclusively from Shale will be eligible for the 36 production months at 5%. (The fluid code assigned by the AER must be “Shale Gas Only”).

What is the cap for the Shale Gas New Well Royalty Rate and what is the maximum number of production months?

There is no volume cap.  All qualifying Shale well events in a well contribute to a single Shale gas cap.

The New Well Royalty Rate and Shale Gas New Well Royalty Rate will run concurrently. Therefore, a qualifying well event under New Well Royalty Rate and the Shale Gas New Well Royalty Rate will have a maximum of 36 production months at 5%.

Coalbed Methane New Well Royalty Rate Questions

What qualifies and what doesn't under the Coalbed Methane New Well Royalty Rate?

To qualify, a well event must:

  • have a fluid code of “Coalbed Methane–Coals Only” when it commences production, and
  • have no production prior to May 1, 2010, and
  • have a Crown interest greater than zero when it commences production. 
  • Re-entry, reactivated, lengthened, and deepened well events may qualify for the Coalbed Methane New Well Royalty Rate provided there is NO prior production from the well event.
    • Wells that have prior production and are being brought back on DO NOT qualify.

Must well events produce exclusively from coal formations to qualify for the Coalbed Methane New Well Royalty Rate?

Yes.   All unique well events that produce exclusively from coals will be eligible for the 36 production months at 5%.  I.e. The Fluid Code assigned by the AER must be “Coalbed Methane-Coals Only”

What is the cap for the Coalbed Methane New Well Royalty Rate and what is the maximum number of production months?

There is a Crown production cap of 11,924 m3 oil equivalent (750 million cubic feet of gas). All qualifying Coalbed Methane well events in the well contribute to a single Coalbed Methane New Well Royalty Rate cap. 

The New Well Royalty Rate and Coalbed Methane New Well Royalty Rate will run concurrently. Therefore, a qualifying well event under New Well Royalty Rate and the Coalbed Methane New Well Royalty Rate will have a maximum of 36 production months or 11,924 m3 oil equivalent (750 million cubic feet of gas) at 5%. 

Horizontal Oil New Well Royalty Rate Questions

What qualifies and what doesn’t under the Horizontal Oil New Well Royalty Rate?

To qualify a well event must meet the following criteria:

  • The well event must be an oil or non-project oil sands well event, and
  • The well event must be horizontal as defined by the AER, and
  • The well event must have a Crown interest greater than zero, and
  • The spud date is on or after May 1, 2010.

The following are examples of well events that would not qualify:

  • A well event deepened, lengthened, reactivated, or re-entered.
  • A Gas over Bitumen well event as per AER shut-in order.
  • An Oil Sands project well event

To qualify a well event must meet the following criteria:

 

Can a horizontal oil well event receive the 5% royalty rate for 12 production months under New Well Royalty Rate and additional production months and volume caps under Horizontal Oil New Well Royalty Rate?

No.  The New Well Royalty Rate and Horizontal Oil New Well Royalty Rate will run concurrently. Therefore, a qualifying well event under New Well Royalty Rate and the Horizontal Oil New Well Royalty Rate will have maximums as defined in the Horizontal Oil New Well Royalty Rate schedule found below.

Does solution gas and gas products, including sulphur, qualify for the 5% royalty rate under the Horizontal Oil New Well Royalty Rate?

Yes.  All products produced from the horizontal oil well event qualify for the 5% maximum royalty rate and all products contribute to the caps.

What if a well has a gas well event and an oil well event in the same well, which caps would apply?

All production from horizontal oil well events contribute to the Horizontal Oil New Well Royalty Rate cap and all production from horizontal gas well events contribute towards the Horizontal Gas New Well Royalty Rate cap.

The volume cap for the Horizontal Oil New Well Royalty Rate is calculated using Crown production.

What is the Horizontal Oil New Well Royalty Rate for an oil well event?

Royalty is calculated at a maximum rate of 5% for qualifying horizontal oil well events.  The caps are set according to the following depth schedule:

Depth (MD)

 Volume Cap of oil equivalent 

    Production Month Cap 

 0 – 2,499.9 m                    7,949 m3              18 months

2,500 -2,999.9 m

                    9,539 m3             24 months

3,000 – 3,499.9 m

                  11,129 m3             30 months

3,500 – 3,999.9 m

                  12,718 m3             36 months

4,000 – 4,499.9 m

                  14,308 m3             42 months
4,500 m + 15,899 m348 months

The rate expires at either the volume cap or production month cap, whichever is first. Where the volume cap is reached during a month, further production will have royalties calculated using the royalty curves.

Does each horizontal oil well event get its own cap?

No.  All horizontal oil well events or legs that qualify will contribute to a single volume cap and a single production month cap at the well level.

How is the depth determined for the Horizontal Oil New Well Royalty Rate?

The depth is defined as the measured distance along the bore of the well from the kelly bushing to the end of the longest Horizontal Oil well event plus all additional horizontal laterals (Measured Depth minus Kick off Point of the Well Event) in a continuous drilling operation (no rig release).  Each drilled metre is to be counted only once. The measured depth is the only requirement there is no need for True Vertical Depth.

Horizontal Gas New Well Royalty Rate Questions

What qualifies and what doesn’t under the Horizontal Gas New Well Royalty Rate program?

To qualify a well event must meet the following criteria:

  • The well event must be a gas well event, and the well event must be horizontal as defined by the AER, and
  • The well event must have a Crown interest greater than zero, and
  • The spud date is on or after May 1, 2010.
  • There is no depth requirement.

The following are examples of well events that would notqualify:

  • A well event deepened, lengthened, reactivated, or re-entered.
  • A Gas over Bitumen well event as per AER shut-in order.
  • An Oil Sands project well event

Can a horizontal gas well event receive the 5% royalty rate for 12 production months under New Well Royalty Rate and additional production months and volume caps under Horizontal Gas New Well Royalty Rate?

No.  The New Well Royalty Rate and Horizontal Gas New Well Royalty Rate will run concurrently. Therefore, a qualifying well event under New Well Royalty Rate and the Horizontal Gas New Well Royalty Rate will have a maximum of 18 production months and volume cap of 7,949 m3 oil equivalent (500 MMcf of gas).

Does oil production qualify for the 5% royalty rate under the Horizontal Gas New Well Royalty Rate?

Yes.  Oil production from the horizontal gas well event qualifies for the 5% maximum royalty rate and contributes to the caps.

What if a well has a gas well event and an oil well event in the same well, which caps would apply?

All production from horizontal oil well events contribute to the Horizontal Oil New Well Royalty Rate cap and all production from horizontal gas well events contribute towards the Horizontal Gas New Well Royalty Rate cap.

The volume cap for the Horizontal Oil New Well Royalty Rate is calculated using Crown production.

What is the Horizontal Gas New Well Royalty Rate for a gas well event?

Royalty is calculated at a maximum rate of 5% for qualifying horizontal gas well events.  The cap is 18 production months or 7,949 m3 oil equivalent (500 MMcf of gas).

The rate expires at either the volume cap or producing month cap, whichever is reached first. Where the volume cap is reached during a month, further production will have royalties calculated using the royalty curves.

Does each horizontal gas well event get its own cap?

No.  All horizontal gas well events or legs that qualify will contribute to a single volume cap and a single production month cap at the well level.