Royalty Adjustment Program for Deep Marginal Gas Wells (RAP)

1. Royalty Adjustment Program for Deep Marginal Gas Wells (RAP)

2. Welcome to the RAP Presentation Agenda • Introductions • Background • Key changes • Timeline • Implementation details • Illustrations • Reporting requirements Informal and interactive

3. Background The Auditor General requested a review of the Deep Gas Royalty Holiday Program (DGRHP) to determine if the program still represents good value for the Crown. The review determined that the DGRHP is no longer necessary as the program met its original objective to accelerate the search for deeper gas reserves. On August 22, 2006 the RAP was introduced to encourage the development of lower grade natural gas resources at deep depths. These changes are effective as of September 1, 2006. It is designed to target wells that produce below established qualifying production rates (QPR).

4. Key Changes • A well includes all drilling occurrences that share a common surface location. • Royalty adjustments are limited to a maximum of $3,600,000 net royalty per well (gross up factor still applied) • Wells are subject to a maximum production threshold – the QPR. • Determination of the royalty adjustment is calculated using both vertical and non-vertical distances drilled. • Approved wells are subject to a minimum 5% royalty rate each month. • Adjustments will be revoked if the QPR is exceeded. • Oil and Oil Sands wells no longer qualify. • Sunset clause August 31, 2011.

5. DGRHP Timeline The following illustrates important dates for the DGRHP June 1, 1985 Sept 1, 2006 April 1, 2010 April 1, 2012 Spudding or deepening of wells must occur between June 1, 1985 and before April 1, 2010. The well must be drilled on a Crown Agreement with a term commencement date (date acquired) earlier than September 1, 2006. Oil and Oil Sands wells spudded after September 1, 2006 are subject to new eligibility criteria. Benefits remaining on April 1, 2012 are rolled into the new program and subject to a minimum 5% royalty rate.

6. RAP Timeline The following illustrates the important dates for the RAP Sept 1, 2006 April 1, 2010 Aug 31, 2011 Spudding or commencement of deepening must occur on or after September 1, 2006 and before August 31, 2011. April 1, 2010 DGRHP eligibility ends, deep wells assessed for RAP eligibility only.

7. Election of RAP • Wells that are eligible for the DGRHP may elect to receive adjustments under the RAP program rather than an exemption under DGRHP. • Elections must be made prior to spudding or commencement of drilling. • The Designated Representative (DR) or well licensee must make the election in writing to the department. • The department will determine the well’s eligibility for consideration under RAP and provide written notification to the well licensee or DR.

8. Qualifying Criteria Wells must: • Be spudded or deepened on or after September 1, 2006 or for DGRHP eligible wells (lands acquired prior to September 1, 2006) an election can be made, • Be producing from a pool that occurs greater than 2,500 meters TVD, • Be outside the pool boundaries as designated by the Alberta Energy and Utilities Board (EUB) as at June 1, 1985 (outside an existing G-order), • Have average daily production (ADP) that does not exceed the QPR.

9. Non Qualifying Criteria Wells that do not qualify include: • Wells that are 100% freehold, • Wells that have received prior royalty exemptions under a previous program, • Off target wells where a penalty has been assessed, • Wells completed in a drilling spacing unit, where another well within the drilling spacing unit has received a royalty adjustment, • Bitumen wells, • Wells whose crude oil or oil sands production is exempt from royalty, • Wells that produce oil either alone or with gas at a gas-oil ratio of less than 1800:1.

10. Determination of Vertical, Measured and Non-Vertical depths • The vertical depth is determined by using the distance from the surface location Kelley bushing to the lesser of either the total vertical depth of the well or to the base of the natural gas producing interval of the deepest producing zone. • The measured depth is the longest distance in meters measured along the well bore from the Kelley bushing to the lesser of the total measured depth of the well or to the base of the natural gas producing interval of the deepest producing zone. • The non-vertical depth is the measured depth less the vertical depth of the well.

11. TVD, MD and Non-Vertical Depth Kelley bushing Surface Total measured drill depth Vertical depth Measured depth Total vertical drill depth

12. Determination of Average Daily Production • In conjunction with the EUB the department will determine all the drilling occurrences that share a common surface location. • The Average Daily Production (ADP) will include production from all zones within a multi-zone wellbore. • Calculation for ADP = total quantity of raw natural gas and field condensate from all zones produced from the well during the 12 month period DIVIDED BY the number of days in the reporting period. Note: Field condensate volumes will be expressed as a gas equivalent using a conversion rate of 1,000 cubic meters of natural gas per cubic meter of condensate.

13. Diagram of a Well X common surface location Pool A 2,500 meters Pool B Pool C

14. Calculation of Qualifying Production Rate • The qualifying production rate (QPR) approximates an economic threshold for a typical well at varying depths. • For the first 12 month reporting period the QPR is based on the following formula: For wells drilled > 2,500 m but ≤ 3,500 m For wells drilled > 3,500 m

15. QPR continued Where: • QPR = the qualifying production rate for the well • MD = the measured depth of the well on the last day of the applicable period • The QPR for the second 12 month period will be 80% of the first period QPR and 68% of the first period QPR for the third and all subsequent 12 month periods.

16. Adjusted QPR • If a well has an acid gas content of more than 15% by volume, the QPR may be adjusted using the following formula. Adjusted QPR = QPR / [100% - (H2S% + CO2% - 15%)] Where: QPR = the qualifying production rate for the well H2S and CO2 = the % of hydrogen sulphide and carbon dioxide contained in the raw gas stream by volume, respectively. • If the well operator/licensee is seeking to have the adjusted QPR applied, it is their responsibility to provide documentation, for the department’s review, such as a gas analysis report signed by a professional engineer.

17. Vertical Well Figure 1 Surface Vertical depth = 2,900 m Measured depth = 2,900 m Non-vertical depth = 0 Pool A Vertical depth 2,900 m

18. Total Vertical Depth that Extends Past the Pool Figure 2 Surface Vertical depth = 2,700 m Total Vertical depth = 2,900 m Measured depth = 2,700 m Total Measured depth = 2,900 Non-vertical depth = 0 Pool A Pay base of pool 2,700 m Vertical depth 2,900 m

19. Well with Non-Vertical Depth Figure 3 Surface Vertical depth = 3,500 m Measured depth = 4,000 m Non-vertical depth = 500 m Measured depth 4000 m Vertical depth 3,500 m Pool A

20. Total Measured Depth that Extends Past the Pool Figure 4 Surface Vertical depth = 3,200 m Total Vertical depth = 3,400 m Measured depth =3,300 m Total Measured depth = 4,000 m Non-vertical depth = 100 m Measured depth to pay base of pool 3,300 m Pool A Vertical depth to pay base of pool 3,200 m Total vertical depth drilled 3,400 m

21. Determination of Royalty Adjustment Figure 1 Vertical adjustment: 2,900 m (Cumulative value) = $400,000 Non-vertical depth: 2,900 m – 2,900 m = 0 Total net adjustment $400,000 Gross up factor 1.72392 Total gross adjustment $689,568

22. Continued Figure 3 Vertical adjustment: 3,500 m (cumulative value) = $1,000,000 Non-vertical depth: 4,000 m – 3,500 m = 500 m Non-vertical adjustment: 500 m X $1,000 (per meter) = $500,000 Total net adjustment $1,500,000 Gross up factor 1.72392 Total gross adjustment $2,585,880

23. Royalty Adjustment • Royalty adjustments begin on the first day of the month in which the royalty payable on gas production obtained from the well is due. • The entitlement period is 10 years following the finished drilling date of the well. • The adjustment terminates if the well is abandoned. • Limited to a maximum of $3,600,000 per well bore. • The adjustment will not reduce the royalty payable to 0% but rather wells are subject to a minimum 5% royalty rate.

24. Reporting requirements • The royalty adjustment amount is determined based on the Volumetric production, Stream Allocation Factor (SAF) and Owner Allocation Factor (OAF). • In order for an adjustment to be applied against a well’s production, the well must be reported as a single well. • If it is determined that the well is commingling production from different zones, some of which do not qualify for an adjustment, the department will advise how to report the eligible and non-eligible production.

25. Invoices & Statements The department will automate the processes related to this program in the near future; however, until the system enhancement is completed the following processes will occur for all qualified wells: • All wells will be set up as if they are deep gas wells, • In the first month the adjustment will be 100% of the royalty payable, • In the following billing period the 5% royalty will be calculated and charged, • The current royalty exemption statement will be overstated by the 5% royalty charge, • Revised exemption statements will be issued to all participants in the well.

26. Revocation of Adjustments • Each 12 month reporting period the department will re-evaluate each well’s ADP and QPR. • If at any point during the QPR is exceeded, the entire royalty adjustment is revoked. • The effective date of the revocation will be the royalty adjustment commencement date, unless the well was deepened and the excess production is a result of the deepening, then the effective date with be the date the well was deepened.

27. Revocation continued • Any royalty adjustments, received by all working interest owners, will be reversed and royalty payable on the natural gas, gas products and field condensate will be calculated as if the adjustment never arose. • Interest will be charged/paid on all prior period amendments. • Once an adjustment is revoked the department will no longer monitor the well. • It is the responsibility of the royalty client to submit documentation that supports reinstatement of an adjustment.

28. Processing Time Lines • The processing of royalty adjustment applications will be similar to those currently followed in the DGRHP. • Clients can track the progress of their wells on the internet on the Natural Gas Royalty Related Information page.

29. Royalty Adjustment Program Process Flow Web page updated Web page updated Royalty client submissions Royalty Programs gathers data, performs preliminary determination on eligibility & prepares worksheets AEUB performs technical evaluation Royalty Programs reviews technical evaluation results. Web page updated Qualified Denied

30. Qualified Wells Determination of all drilling occurrences' producing from the common surface location. Using the first 6 months of production data the Royalty Programs Group calculates the average daily production (ADP) and qualifying production rate (QPR) for the well. Web page updated Well tentatively denied Well tentatively approved

31. Re-evaluation of Tentative Wells The tentatively approved and tentatively denied wells are re-evaluated using 12 months of production data for the ADP & QPR calculations. Web page updated Well denied and previous adjustments are revoked and royalties are recalculated. Adjustment confirmed Web page updated Each subsequent 12 month reporting period the ADP & QPR are re-evaluated.

32. Thanks for coming!