Drilling Royalty Credit Frequently Asked Questions

The Drilling Royalty Credit program is a short term stimulus providing credits for qualifying drilling during the current economic slowdown. These credits, once established by drilling, will be paid to eligible companies based on their royalty obligations during the program. The program is two years in duration, allowing the establishment of credits through drilling, and payment of credits based on royalty obligations, from April 1, 2009 until March 31, 2011. 

All natural gas, oil and non-project oil sands wells drilled in Alberta that meet the following 4 criteria qualify for this credit:

• Spud date on or after April 1, 2009 before April 1, 2011,
• Finish drill date on or after April 1, 2009 and before April 1, 2011, and
• The well must be drilled for the purpose of extracting conventional oil (subject to the payment of royalty under the Petroleum Royalty Regulation, 2009), natural gas (subject to the payment of royalty under the Natural Gas Royalty Regulation, 2009), or crude bitumen from non-project oil sands wells (subject to payment of royalty under the Oil Sands Royalty Regulation, 2009), and
• The well must be drilled on Alberta Crown mineral rights.

 

The following wells do not qualify for this program:

• Wells drilled on project leases in an approved oil sands project or pending project application as defined under the Oil Sands Royalty Regulation, 2009,
• Gas over bitumen wells, and 
• Wells drilled for purposes other than production, including disposal and injection wells.

 

Re-entry wells do not qualify for the DRC but are eligible for the New Well Royalty Reduction subject to the qualification criteria for that program. 

The DRC was designed specifically to encourage the drilling of new wells. 

The goals of the DRC are to provide support to energy companies to stimulate drilling activity and ultimately increase royalty receipts by the Government of Alberta. 

The timeframe for the programs coincides with the Alberta Government’s 2009/2010 and 2010/2011 fiscal years. 

Yes, however any drilling credits received for that well will be deducted from well costs of the Project. 

Wells that are part of an approved or pending project application of an Oil Sands Project under the Oil Sands Royalty Regulation, 2009 cannot receive the drilling credit. 

The credit is established at the well level. 

Dry holes that were drilled for the purpose of extracting oil, crude bitumen or gas and were unsuccessful will be eligible. 

Yes, wells must be drilled in whole or in part on Alberta Crown mineral rights. Wells drilled on 100% freehold mineral rights do not qualify. 

The credit of $200/metre is for 100% Crown interest, and where Crown interest is less than 100%, the credit is prorated based on Crown interest (e.g. 50% Crown interest = $100/metre credit). 

For each well drilled within the timeframe of the program, the Alberta Department of Energy will establish a credit against royalties due to the Crown on company-wide production of natural gas, oil and non-project crude bitumen of up to $200 per unique drilled meter dependent on each well’s Crown interest (each meter counted only once in multi-lateral wells).  The credit will be paid to eligible companies on the basis of their company-wide Crown production of natural gas, oil and non-project crude bitumen. 

The $200/m drilling credits will be paid to eligible companies based on net royalties. 

Drilling credits apply to net royalties after deduction for costs and allowances, including GCA. 

The drilling credit program is based on the depth of a well and will have no affect on the relief calculated in EOR. 

The NGDDP would be applied first, thereby lowering net royalties paid. The $200/m drilling credits will be based on net royalties after all deductions (excluding the drilling credits). 

A drilled metre is a physical metre of drilling, horizontally or vertically. For multi-lateral wells this would include all branches as long as each drilled metre is only counted once. 

The Crown interest requirement is tied to the Alberta Government’s ability to effectively lower royalties only on Crown production. Alberta does not receive any royalty from production of freehold rights. 

All companies that have production subject to Alberta Crown royalties in fiscal 2009/2010 and fiscal 2010/2011 will be eligible for this credit. 

No, drilling credits will not be allowed to reduce corporate royalties from oil, gas and non-project oil sands wells to less than zero. 

Credits will not reduce monthly gas, oil or non-project oil sands royalties payable. Royalty payers must pay the full amount of the monthly gas royalty invoice, oil royalties payable or non-project oil sands royalties payable.

Credits will be paid to eligible companies (defined below) on the basis of their fiscal 2009/2010 and fiscal 2010/2011 corporate Crown royalties in a separate cheque issuance process. Once credits are duly assigned to eligible companies and Working Interest Ownership of oil and non-project oil sands wells is known, there are no additional requirements to receive drilling credits.

 

A royalty payer is either a Royalty Client as defined under the Natural Gas Royalty Regulation, 2009, an Operator, as defined under the Petroleum Royalty Regulation, 2009 or an Operator as defined under the Oil Sands Royalty Regulation, 2009.  

The credit is available whether Alberta Royalty Framework (ARF) or Transition rates are selected, and does not affect royalty rates applicable at the well level. Selection of ARF or Transition rates still applies for wells qualifying for that selection. 

Yes, receipt of drilling credits and the new well royalty reduction can be obtained for a single well as long as the criteria for each are met. 

The licensee of a gas, oil or non-project oil sands well (or dry well targeted at natural gas, oil or crude bitumen production) must submit an allocation to the Department of Energy providing a one-time assignment of the credits established by the drilling of a well to an eligible company.
An eligible company who has drilling credits assigned to it would receive a cheque refunding all or a portion of the credit amount established against royalties obligations of that eligible company on conventional oil, non-project oil sands wells and natural gas each month based on the scales defined below until credits registered to that eligible company are consumed or the program ends. 

An eligible company is a company that is or will be recognized as having a Crown royalty obligation. An eligible company is identified in the records of the Department of Energy as gas royalty client as defined under the Natural Gas Royalty Regulation, 2009, and/or will be identified in the records of the Department as a Working Interest Owner (WIO) with royalty obligations in oil and non-project oil sands wells subject to the payment of royalty by the operator of the well under the Petroleum Royalty Regulation, 2009 or the Oil Sands Royalty Regulation, 2009. 

Currently, only the battery operator for oil or non-project oil sands well is identified as a royalty payer in the records of the Department of Energy. Establishing the appropriate level of benefit (10% to 50% - see below) and assigning credits to only these operators would result in inequities to oil well working interest owners. The program is designed to apply to corporate production and corporate royalties.
In order to both apply credits against oil WIO royalty obligations, and to know oil WIO production subject to Alberta Crown royalties (credit deduction rate and maximum credit available – see below), the WIO of all wells producing oil in Alberta will be input and maintained by Industry via the Petroleum Registry of Alberta (PRA). This WIO information will be required from January 1, 2008 onward as the sliding scale (see below) uses calendar 2008 as the basis of production. This information will be entered into the PRA by industry once processes, systems and legal authority are in place. This WIO information will require ongoing maintenance by industry. 

For production subject to payment of royalties under the Petroleum Royalty Regulation, 2009, or the Natural Gas Royalty Regulation, 2009, and non-project oils sands wells subject to payment of royalties under the Oil Sands Royalty Regulation, 2009, each eligible company will be categorized using the Credit Drawdown and Maximum Percentage scale below to determine both the rate of payment of credits established by drilling from royalties and the maximum credit obtainable by eligible companies under the DRC program. The Alberta Department of Energy will categorize each eligible company subject to Alberta Crown production in 2008 according to the records of the Department. Each eligible company will be provided their categorization by the Alberta Department of Energy (once processes are in place). This categorization will be determined by the Alberta Department of Energy at its sole discretion.
Eligible companies with no 2008 production subject to Alberta royalties will initially be classified at the ‘Greater than 3,975 m3/day’ category and receive the 10% Credit Drawdown and Maximum Percentage rate. After March production is reported in the first fiscal year in which production started, either April 1, 2009 to March 31, 2010 or April 1, 2010 to March 31, 2011, these companies will be reclassified by applying that fiscal year’s production to the scale below and royalty credits will be recalculated.

Company Alberta Crown 2008 Average Production in e3m3/day including equivalents (subject to payment of royalty under the Petroleum Royalty Regulation, 2009, or the Natural Gas Royalty Regulation, 2009 and the non-project oil sands well subject to payment of royalties under the Oil Sands Royalty Regulation, 2009).	Credit Drawdown and Maximum Credit Percentage
Greater than 0 m3/day and less than or equal to 1,590 m3/day (10,000 boe/d)	50%
Greater than 1,590 m3/day and less than or equal to 2,385 m3/day (15,000 boe/d)	40%
Greater than 2,385 m3/day and less than or equal to 3,180 m3/day (20,000 boe/d)	30%
Greater than 3,180 m3/day and less than or equal to 3,975 m3/day (25,000 boe/d)	20%
Greater than 3,975 m3/day (25,000 boe/d)	10%

 

The intent of the DRC is to support the licensee and their Working Interest Partners in the drilling of a well. The Department therefore encourages the assignment of credits to the Working Interest Partners of the well being drilled, but will not restrict credits being assigned to royalty payers who are not Working Interest partners in the well. 

Credits for wells drilling from April 1, 2009 to March 31, 2010 will be paid based on royalty obligations arising in the fiscal years starting April 1, 2009 and ending March 31, 2011. Credits for wells drilled from April 1, 2010 to March 31, 2011 will be based on royalty obligations arising in the fiscal year starting April 1, 2010 and ending March 31, 2011.  The Department will calculate on a monthly basis, cumulative royalty obligations as well as drilling credits established and paid. 

Yes.
1. For wells drilled from April 1, 2009 to March 31, 2010, the maximum amount of credit that can be received by reduction of royalty obligations is equal to the sum of:

• An eligible company’s total royalty obligation from April 1, 2009 to March 31, 2011 (fiscal 2009/2010 and fiscal 2010/2011) subject to the Natural Gas Royalty Regulation, 2009 multiplied by that eligible company’s Credit Drawdown and Maximum Credit Percentage rate, plus
• An eligible company’s total royalty obligation from April 1, 2009 to March 31, 2011 (fiscal 2009/2010 and fiscal 2010/2011) subject to the Petroleum Royalty Regulation, 2009, in dollars based on the applicable par price, multiplied by that eligible company’s Credit Drawdown and Maximum Credit Percentage rate, plus
• An eligible company’s total royalty obligation from April 1, 2009 to March 31, 2011 (fiscal 2009/2010 and fiscal 2010/2011) for non-project oil sands wells subject to payment of royalty under s. 27 of the Oil Sands Royalty Regulation, 2009, multiplied by that eligible company’s Credit Drawdown and Maximum Credit Percentage rate.

2. For wells drilled from April 1, 2010 to March 31, 2011, the maximum amount of credit that can be received by reduction of royalty obligations is equal to the sum of:

• An eligible company’s total royalty obligation from April 1, 2010 to March 31, 2011 (fiscal 2010/2011) subject to the Natural Gas Royalty Regulation, 2009 multiplied by that eligible company’s Credit Drawdown and Maximum Credit Percentage rate, plus
• An eligible company’s total royalty obligation from April 1, 2010 to March 31, 2011 (fiscal 2010/2011) subject to the Petroleum Royalty Regulation, 2009, in dollars based on the applicable par price, multiplied by that eligible company’s Credit Drawdown and Maximum Credit Percentage rate, plus
• An eligible company’s total royalty obligation from April 1, 2010 to March 31, 2011 (fiscal 2010/2011) for non-project oil sands wells subject to payment of royalty under s. 27 of the Oil Sands Royalty Regulation, 2009, multiplied by that eligible company’s Credit Drawdown and Maximum Credit Percentage rate.

 

No, drilling credits will not reduce royalties paid on project oil sands wells. 

Yes, an application must be made assigning credits to eligible companies. Companies will be advised of the process once it is fully developed. 

If the drilled depth is amended the credit will be adjusted to accurately reflect the proper amount.  

The program is in effect for the fiscal 2009/2010 and 2010/2011 years. The ability of companies to establish credits is through drilling (spud and finish drill date) in fiscal 2009/2010 and 2010/2011.

Delivery of final payment for credits established in the requisite timeframe by drilling will occur after credit assignment is completed (by application) by the licensee and after royalties are reported/invoiced for the March 2011 production month. All payments for the DRC program will be completed after the June 2011 submission deadline and the annual gas invoice. Adjustments to production, royalties, drilled depth, etc. will be made using existing processes for those adjustments. Any changes to credit payments under the DRC will then be made as required. 

The following provides examples of how the DRC will work under various conditions. ADOE = Alberta Department of Energy.

Scenario 1 - Company Alpha:

Company Alpha:

• 2008 calendar Crown production 500 boe/day = ‘Credit Drawdown and Maximum Credit Percentage’ of 50%.
• 2009/2010 and 2010/2011 fiscal Crown production estimate 1,000 boe/day.
• 2009/2010 and 2010/2011 estimated monthly royalties of $340,000, or $4,080,000 for the year.

Drilling:

• 6 wells, each 3,000 meters and on 100% Crown land drilled in September, 2009.
• Company Alpha is the 100% owner of all 6 wells.

Credit Establishment:

• Total credit available by drilling = $3.6 million (3,000 meters * 6 wells * 100% Crown * $200/meter)
• Maximum credit obtainable by Company Alpha = approximately $4 million ($4,080,000 in estimated total fiscal 2009/2010 plus $4,080,000 in fiscal 2010/2011 royalties paid * 50%).
• Company Alpha elects to assign 100% of the credits to itself.

Credit Payment:

• Annual Royalties Paid: $8,160,000
• Maximum Credits Obtainable through DRC: $4,080,000
• Credits Established by Drilling: $3,600,000
• Credits Paid: $3,600,000
• Credits Remaining at Program’s End: $0

Scenario 2 - Company Blue:

Company Blue:

• New start up in April, 2010, with no 2008 calendar or fiscal 2009/2010 Crown production. As a result Company Blue will be initially assigned a ‘Credit Drawdown and Maximum Credit Percentage’ of 10%, which will be adjusted using actual Crown production once known.
• Company Blue is the licensee of the well.
• The well being drilled is the only well Company Blue has an interest in.

Company Green:

• A small producer with 5,000 boe/day Crown production in 2008, rixcal 2009/2010 and fiscal 2010/2011, yielding a ‘Credit Drawdown and Maximum Credit Percentage’ of 50%.
• This well being the only well Company Green is participating in during the duration of the DRC program.
• Estimated monthly royalties of $1,750,000, or fiscal year royalties of $21 million for each of the two fiscal years.

Drilling:

• 1 well, drilled in February of 2011, 1,000 meters deep on 50% Crown land.
• Company Blue owns 75% of the well, with Company Green owning 25% of the well.

Credit Establishment:

• Total credit established by drilling = $100,000 (1,000 meters * 1 well * 50% Crown * $200/meter).
• As this is Company Blue’s only well, if it does not come on production during fiscal 2010/2011 there will be no Company Blue 2010/2011 royalties from which ADOE would pay drilling credits.
• Company Green has a maximum credit obtainable of $10.5 million ($21 million * 50%).  (Note that royalties paid in fiscal 2009/2010 are not included in this maximum value.) 
• Company Blue as licensee is responsible for credit assignment and, after reaching agreement with Company Green, assigns 100% of the credit to Company Green.

Credit Payment:

• Fiscal 2010/2011 annual Royalties Paid by Company Green: $21,000,000
• Maximum Credits Obtainable through DRC: $10,500,000
• Credits Established by Drilling: $100,000
• Credits Paid to Company Green: $100,000
• Credits Remaining at Program’s End: $0

Scenario 3 - Company International:

Company International:

• Large multinational company with over 100,000 boe/day of calendar 2008 Crown production, resulting in a ‘Credit Drawdown and Maximum Credit Percentage’ of 10%.
• Has a very aggressive drilling plan, and knows that this program will exceed its maximum obtainable credits through the DRC.

Company X:

• 2008 calendar Crown production of under 10,000 boe per day, resulting in a ‘Credit Drawdown and Maximum Credit Percentage’ of 50%.
• Estimated monthly royalties of $2 million, or royalties paid of $24 million for the fiscal year.
• Has no fiscal 2009/2010 or 2010/2011 drilling plans.

Drilling:

• Company International drills 10 wells, one in each month from May, 2009 to February, 2010, on 100% Crown land. Each well has 6,000 unique meters drilled in a multilateral well.
• Company International owns 90% of the wells. Company International is the well licensee for the wells.
• Company X is a 10% owner of all the wells.

Credit Establishment:

• Credit established by each well through drilling = $1.2 million (6,000 meters * 1 well * 100% Crown * $200/meter).
• Total credit established is $12,000,000 ($1.2 million * 10 wells).
• As Company X is not drilling, it has unused credits. Company International, as licensee for the wells, after reaching agreement with Company X, assigns 100% of the credits for all wells to Company X.

Credit Payment:

• Annual Royalties Paid by Company X: $48,000,000
• Maximum Credits Obtainable through DRC: $24,000,000
• Credits Established by Drilling: $12,000,000
• Credits Paid to Company X: $12,000,000
• Credits Remaining at Program’s End: $0

Scenario 4 - Company Wednesday:

• Company Wednesday had daily production in calendar 2008 of 5,000 boe per day, and has been assigned a ‘Credit Drawdown and Maximum Credit Percentage’ rate of 50%.

Drilling:

• In early April, 2010 the company drills a 1,500 meter well on 100% Crown land with no partners.

Credit Establishment:

• Company Wednesday assigned credits to itself after the well was drilled, resulting in the establishment of $300,000 in credits (1,500 meters * $200 per meter * 100% Crown interest).

Company Wednesday UPDATED:

• At the end of April, 2010, Company Wednesday sells off most of its producing assets, resulting in royalties paid in April, 2010 of $340,000, and after that of $20,000 of royalties paid per month. Total royalties paid during the 2010/2011 fiscal year is $560,000.

Credit Payment:

• Annual Royalties Paid: $560,000
• Maximum Credits Obtainable through DRC: $280,000
• Credits Established by Drilling: $300,000
• Credits Paid to Company X: $280,000
• Credits Remaining at Program’s End: $0

Note that $20,000 in credits established were not received by Company Wednesday because it exceeded the maximum credits obtainable based on royalties paid in fiscal 2010/2011 only.