Manitoba Petroleum Fiscal Regime
|
|  Yüklə 5.94 Mb.
|
Provincial Freehold Oil PRODUCTION TaxESThe Oil and Gas Production Tax Act levies a tax on production from freehold oil and gas rights. The tax is based on monthly production from a spacing unit, or production allocated to a unit tract under a unit agreement or order. For horizontal wells, the tax is calculated per spacing unit based on the production allocated to spacing units within the drainage area in accordance with any production allocation agreement. If there is no production allocation agreement, it is assumed that the horizontal well's production is divided equally among all spacing units in the drainage unit. The Act provides that the operator of a well is responsible for payment of the tax on any freehold oil production. The oil and gas rights owner's and any other royalty or working interest owner's share of the tax is deducted from the payment made to them by the operator from the sales revenue. A working interest owner, who takes its oil in kind and markets the oil, may be designated by the Director as a special operator. A special operator is responsible for filing returns and payment of the tax for its share of the production. The freehold oil production tax is determined under The Oil and Gas Production Tax Regulation and is based on the formulae shown in Table 3. Figure 3 and Table 4 show freehold oil production tax rates as a function of production. Freehold oil production tax rates are not price sensitive. Table 3: Manitoba Freehold Oil Production Tax Rate (%) Determination
P is the monthly oil production in cubic metres (m3)  Table 4: Freehold Oil Production Tax Rates (%) – Example
Minimum Production Tax (MPT) For a well drilled after December 31, 2013 and before January 1, 2019, there is a requirement to pay a minimum production tax. As with Crown royalties the payment will be based on the volumes established in the Crown Royalty and Incentives Regulation for minimum Crown royalty volumes. The production tax payment will be required on the following volumes: 1.(a)8,000 m3 if the well is (i)a horizontal well, (ii)a deep development well completed for production in the Birdbear Formation or a deeper formation, or (iii)a deep exploratory well drilled below the Birdbear Formation, or (b)4,000 m3 if the well is a non-deep exploratory well drilled more than 1.6 kilometres from a well cased for production from the same or deeper zone: or (c)500 m3 if the well is a vertical oil well that is not subject to subclauses (a) or (b); 2. 500 m3 if the well was a marginal oil well that undergoes a major workover after December 31, 2013 but before January 1, 2019. The production tax payable on holiday volumes is the lesser of
Minimum Production Tax Rate Example 1 (MPT 1) In this example we have an MDIP 2014 horizontal well situated on freehold minerals and the well traverses three spacing units. In spacing unit 1 there is a previously existing vertical well that was drilled in 2013. That well is a third tier well and its holiday volume has been utilized. The horizontal well has MDIP 2014 holiday volume and the production from the vertical well is not considered in the horizontal well royalty calculations. The oil from the horizontal well is classified as New Oil. 
The horizontal well production is allocated to each spacing unit: Location 1 - 33% Location 2 - 38% Location 3 - 29%
After the horizontal well has produced all of the MDIP 2014 holiday volume, regular production tax calculations will resume. The horizontal well produced 200 m3 of new oil and the vertical well produced 45 m3 of third tier oil. In this case the 45 m3 of production from the vertical well must be included in the calculation of production taxes for spacing unit 1. Total production for spacing unit 1 P = 66 + 45 = 111 m3. Step 1: Calculate new oil production tax using a P of 111 m3 19.59 – 820/P 19.59 = 820/111 = 12.20% For the 66 m3 of new oil production the tax rate will be 12.20% Step 2: Calculate third tier royalty using a P of 111 m3 11 – 465/P 11-465/111 = 6.81% For the 45 m3 of third tier oil production the tax rate will be 6.81% Step 3: Total production tax payable 66 x 12.20% + 45 x 6.81% = 11.11 m3 Royalties Payable = Price x 11.11 m3
Location 1 - 33% Location 2 - 38% Location 3 - 29% For this month the horizontal well has produced 200 m3 of oil.
Assuming an oil price of $600 m3, the total amount owning will be: (1.98 x $600) + (2.09 x $600) + (58 x .01 x 600) = $1188 + $1254 + $348 = $2790
Assuming a price of $600 per m3, the total amount owing will be: (1.94 x $600) + (66 x 1.875% x 1% x $600) = $1,164 + $7.43 = $1171.43 OR
(1.94 x $600) + (1.24 m3 x 1% x $600) = $1,164 + $7.43 = $1171.43 Pressure Maintenance Project Incentive (PMPI) The calculations for royalties and production taxes for units are dependent upon the historical regime in which the units were created. For new waterfloods or other EOR (Enhanced Oil Recovery) projects approved after April 1, 1999, the Branch will determine a Third Tier EOR Factor. The Third Tier EOR Factor will be applied to old oil and new oil production from the approved project area to determine a project’s Third Tier EOR Production. The Third Tier EOR Factor is determined at the time of project approval and is based on the ratio of incremental EOR recoverable reserves to total remaining recoverable reserves for the project area. The Third Tier EOR Factor is the fraction of old oil and new oil from the project area that qualifies as Third Tier EOR. Under MDIP 2014, calculations of unit royalties and production taxes have not been dramatically altered with the exception of allowing an automatic increase to 18 months of pressure maintenance project incentive for wells converted that have a remaining holiday volume. When converting or placing a WIW (Water Injection Well) on injection, the PMPI allows for 4 spacing units (adjoined to a vertical well, or 4 spacing units that are part of the horizontal allocation for a horizontal well) to receive a tax and royalty incentive. These selected spacing units do not pay any taxes and royalties. The royalty and production tax holiday is for 18 months for a well converted to injection which has a remaining holiday volume, or 12 months for wells drilled as injection wells. Under MDIP 2014 all unselected spacing units of wells with remaining MDIP 2014 holiday volume will be required to pay MCR or MPT. Scenario 1 A horizontal well is drilled during 2014 into an existing unit and receives MDIP 2014 holiday volume. For the purposes of taxes and royalties, the production from this well is excluded from the unit production. Minimum crown royalty/minimum production tax will be payable on the production from this well. These calculations would be the same as the previous examples MCR 1a and MPT 1a. Scenario 2 A new unit is formed after December 31, 2013, and it consists of a 2014 MDIP well which is on holiday and two wells drilled prior to 2014. Any wells with a remaining holiday volume that are converted to injection wells will allow for up to 4 selected spacing units to receive an 18 month holiday from the payment of all production taxes and royalties. After 18 months the PMPI expires. Any wells that are on holiday during the PMPI period will continue to countdown holiday volumes assigned to that well regardless of whether it is receiving PMPI. 
In this example there are 3 unit wells on Crown minerals. The middle well was drilled prior to 2013 and then converted to injection in 2014. The well has remaining holiday volume. Because of this, the well’s PMPI period is extended from 12 months to 18 months. MDIP 2014 allows for 4 spacing units to be selected adjacent to the converted injection well. (If the injection well is a horizontal well, 4 spacing units representing the majority of the horizontal drainage may be selected). The selected spacing units 9, 12, 14 and 15 will receive PMPI. These spacing units do not pay any royalties (including MCR) during the entire PMPI period. Spacing units 10, 11, 13 and 14 were not selected for PMPI. Spacing units 13 and 16 which belong to an MDIP 2014 well must be considered for MCR using the same methodology as MCR 1a. Locations 10 and 11 belong to a pre MDIP 2014 well and do not have to pay MCR. After 18 months the PMPI expires. At that point the MDIP 2014 well still has a remaining holiday volume therefore all spacing units for this well must be considered for MCR. The production from this well is not included in the unit calculations. |
